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

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ORGANIZING DEPARTMENT

ENI S.p.A. Divisione Agip

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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

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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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General Index Chapter 1 - Completion Design

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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

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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

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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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TITLE Well Completion & Workover Course

Volume 1

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


- 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



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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

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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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

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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

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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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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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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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Tbg Retrievable SV

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Tbg 3 1/2"

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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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Tbg 2 7/8"

Packer with gas venting

Nipple

DPPT Circ. Valve

ESP with rotary gas separator

b. proposed completion for Zatchi


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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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TYPE OF ACTIVITY'

ISSUING DEPT.

DOC. TYPE

REF. N.

OF

TEAP

P

1

R

1

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57

8791


Volume 1

CHAPTER 2 - MATERIAL SELECTION DISTRIBUTION LIST TEAP STAP – Archive


- 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



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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2.

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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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.


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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.


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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


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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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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:


ARPO


IDENTIFICATION CODE

PAG

13

OF

57


0 1

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).


ARPO

IDENTIFICATION CODE


PAG

14

OF

57


0 1

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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IDENTIFICATION CODE

15

OF

57


2.2.1.2.2

PAG

0 1

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


IDENTIFICATION CODE

PAG

16

OF

57


0 1

- 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:


ARPO


IDENTIFICATION CODE

PAG

17

OF

57


0 1

- 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.

ARPO


IDENTIFICATION CODE

PAG

18

OF

57


0 1

- 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.


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IDENTIFICATION CODE

19

OF

57


2.3

PAG

0 1

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


ARPO

IDENTIFICATION CODE


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

20


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


ARPO


IDENTIFICATION CODE

11

12

13

14

15

16

17

18

19

20

21

OF

57

0 1

OCTG IN H2S , CO2 AND CL- WELLS Corrosive environment

10

21


2.3.1.1.4

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 20050000 0.2< pCO2 MAX ≤ 100 0.005< pH2S MAX ≤ 0.1 FBHT ≤ 250 Cl-≤ 20000 pCO2 MAX ≤ 100 0.005< pH2S MAX ≤ 0.1 FBHT ≤ 250 Cl-≤ 50000 0.2< pCO2 MAX ≤ 100 0.005< pH2S MAX ≤ 0.1 200 < FBHT ≤ 250 Cl-≤ 50000 0.2< pCO2 MAX ≤ 100 0.1< pH2S MAX ≤ 1 FBHT ≤ 200 Cl-≤ 50000 0.2< pCO2 MAX ≤ 100 0.1< pH2S MAX ≤ 1 FBHT ≤ 250 Cl-≤ 50000 0.2< pCO2 MAX ≤ 100 0.1< pH2S MAX ≤ 1 FBHT ≤ 200 Cl-> 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.

ARPO


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


Alternative Choice

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


Alternative Choice

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


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

22


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


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


ARPO


IDENTIFICATION CODE

12

13

14

15

16

17

18

19

23

OF

57


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 ≤ 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.


25%-Cr-C.W.


25%-Cr


28%-Cr


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



ARPO


IDENTIFICATION CODE

PAG

24

OF

57


0 1

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 <0.035


Alternative Choice

Tubing-Hanger AISI-4140-HRC-22-Max Tubing-Head-Adapter AISI-4135-HRC-22-Max Tbg-Spool AISI-4135-HRC-22-Max Cross AISI-4135-HRC-22-Max Top-Adapter AISI-4135-HRC-22-Max Casing-Spool AISI-4135-HRC-22-Max Stud ASTM-A193-B7M Nut ASTM-A194-2M Automatic-Master-Valve-Materials Body-Bonnet-Flanges AISI-4135-HRC-22-Max Gate&Seats AISI-4140-HRC-22-Max Stem AISI-4140-HRC-22-Max Manual-Master-Valve-Materials Body-Bonnet-Flanges AISI-4135-HRC-22-Max Gate&Seats AISI-4140-HRC-22-Max Stem AISI-4140-HRC-22-Max Tubing-Hanger AISI-4140 Tubing-Head-Adapter AISI-4135 Tbg-Spool AISI-4135 Cross AISI-4135 Top-Adapter AISI-4135 Casing-Spool AISI-4135 Stud ASTM-A193-B7 Nut ASTM-A194-2H Automatic-Master-Valve-Materials Body-Bonnet-Flanges AISI-4135 Gate&Seats AISI-4140 Stem AISI-4140 Manual-Master-Valve-Materials Body-Bonnet-Flanges AISI-4135 Gate&Seats AISI-4140 Stem AISI-4140


ARPO

IDENTIFICATION CODE


OF

57

0 1

WELL HEAD & XMAS TREE MATERIALS - ONLY CO2 AND CL- WELLS

Corrosive environment 3

25


2.3.1.3.2

PAG

0.2< pCO2 MAX ≤ 100 FTHT ≤ 150 Cl- ≤ 50000


Alternative Choice

Tubing-Hanger

13%-Cr-80Ksi-Max F6NM

Tubing-Head-Adapter

13%-Cr-80Ksi-Max F6NM AISI-4135 13%-Cr-80Ksi-Max F6NM 13%-Cr-80Ksi-Max F6NM Carbon Steel AISI-41XX

Tbg-Spool Cross Top-Adapter Casing-Spool

Bolting-Materials Stud Nut

ASTM-A193-B7 ASTM-A194-2H

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

13%-Cr-80Ksi-Max F6NM 13%-Cr-80Ksi-Max Monel K 500 17-4-PH

Automatic-Master-Valve-Materials Body-Bonnet-Flanges Gate&Seats Stem 4

pCO2 MAX ≤ 100 150 < FTHT ≤ 200 Cl- ≤ 50000

Tubing-Hanger

Tubing-Head-Adapter Tbg-Spool Cross Top-Adapter Casing-Spool

13%-Cr-80Ksi-Max F6NM 13%-Cr-80Ksi-Max Monel K500 17-4-PH Monel K500 Inconel 718 AISI-4135 & Internal Cladding w/ Inconel 625 AISI-4135 AISI-4135 & Internal Cladding w/ Inconel 625 Monel K500 AISI-4135 & Internal Cladding w/ Inconel 625 Monel K500 AISI-4135


ASTM-A193-B7 ASTM-A194-2H

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

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

Automatic-Master-Valve-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.

ARPO


IDENTIFICATION CODE

Body-Bonnet-Flanges Gate&Seats Stem

5

OF

57

0 1

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

WELL HEAD & XMAS TREE MATERIALS - H2S, CO2 AND CL-

Corrosive environment Material First Choice Tubing-Hanger pCO2 MAX ≤ 100 pH2S MAX ≤ 0.005 FTHT ≤ 150 Cl-≤ 50000 Tubing-Head-Adapter Tbg-Spool Cross Top-Adapter Casing-Spool Bolting-Materials Stud Nut

6

26


2.3.1.3.3

PAG

pCO2 MAX ≤ 100 pH2S MAX ≤ 0.2 FTHT ≤ 150 Cl-≤ 50000

Alternative Choice F6NM

13%-Cr-80Ksi Max F6NM AISI-4135-HRC-22-Max 13%-Cr-80Ksi Max F6NM 13%-Cr-80Ksi Max F6NM AISI-4135-HRC-22-MAX

ASTM-A193-B7M ASTM-A194-2M Manual-Master-Valve-Materials Body-Bonnet-Flanges 13%-Cr-80Ksi Max F6NM Gate&Seats 13%-Cr-80Ksi Max Stem 17-4-PH F6NM Automatic-Master-Valve-Materials Body-Bonnet-Flanges 13%-Cr-80Ksi Max F6NM Gate&Seats 13%-Cr-80Ksi Max Stem 17-4-PH F6NM Tubing-Hanger F6NM Monel K500

Tubing-Head-Adapter Tbg-Spool Cross Top-Adapter Casing-Spool Bolting-Materials Stud Nut

F6NM AISI-4135-HRC-22-Max F6NM F6NM AISI-4135-HRC-22-Max ASTM-A193-B7M ASTM-A194-2M

Manual-Master-Valve-Materials Body-Bonnet-Flanges F6NM Gate&Seats 13%-Cr-80Ksi Max STELLITE-6 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

IDENTIFICATION CODE


PAG

27

OF

57


0 1

Stem

7

pCO2 MAX ≤ 100 pH2S MAX ≤ 0.8 FTHT ≤ 150 Cl-≤ 50000

Monel K500 Automatic-Master-Valve-Materials Body-Bonnet-Flanges F6NM Gate&Seats 13%-Cr-80KSI-Max Stellite-6 Stem Monel K500 Tubing-Hanger Inconel 718

Tubing-Head-Adapter Tbg-Spool Cross

Top-Adapter

AISI-4135 & Internal-Cladding Inconel 625 AISI-4135-HRC-22-Max AISI-4135 & Internal Cladding Inconel 625 Monel K500 AISI-4135 & Internal-Cladding Inconel 625 Monel K500


Monel K500 Monel K500

Automatic-Master-Valve-Materials Body-Bonnet-Flanges

8

pCO2 MAX ≤ 100 pH2S MAX ≤ 0.8 Cl-> 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


ARPO


IDENTIFICATION CODE

PAG

28

OF

57


0 1

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


ARPO

IDENTIFICATION CODE


PAG

29

OF

57

REVISION 0 1

TEAP-P-1-R-8791

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


ARPO

IDENTIFICATION CODE


PAG

30

OF

57

REVISION 0 1

TEAP-P-1-R-8791

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


ARPO


IDENTIFICATION CODE

31

OF

57


2.4

PAG

0 1

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


ARPO


IDENTIFICATION CODE

PAG

32

OF

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0 1

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

• Service Temperature 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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(-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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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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- 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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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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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) 2 2 1 1 1 2 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 (<65% cold) 1 x 3 x 3 3 1 1 1 1 2 1 1 Acids Acetic (hot) 4 4 4 2 2 3 3 4 1 3 2 1 1 Surfactants 2 4 1 x 1 3 1 1 1 1 1 1 1 Chlorinated Solvents 1 4 4 4 3 3 4 1 1 3 1 1 1 Mhetane 2 2 1 1 1 1 4 1 1 1 1 1 1 CO2 2 1 1 1 1 1 2 2 1 2 1 1 1 H2 S 2 4 4 4 1 3 1 2 1 2 1 1 1 Phisical Properties Tear resistances Good V. Good Good Good Good Good Poor Good Good Fair V. Good Fair Good Abrasion Resistances V. Good V. Good Good Good Good Good Good Good Good Fair V. Good Fair Good Compression Set Resistances Good Good V. Good Fair N/A Good Fair Fair N/A Fair N/A Poor N/A Resiliences High High Med Med N/A Med Med Low N/A Fair N/A Low N/A Gas Impermeability Fair Good Fair V. Good Good Good Good V. Good Good Good Good V. Good Good Key to performances rating rating Significance rating Significance 1 Good Satisfactory performances in relatively high level of chemical 4 Bad No tollerance to chemical DO NOT USE 2 Fair Performances depends on desidered life and level of chemical x No data avaible 3 Poor Performances depends on desidered life and level of chemica 4 Bad


TABLE 5

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service duties are shown in Table 5. The data should be used only as a general guide to the performance of a class of material. Variation in performance exists across the grades within a class. Material selection is made by assessing the effects of individual environments and rejecting unsuitable material classes where there is a definite need for resistance. The selected materials should have optimum performance across all media. Up till now, it is only the 'class' of seal material which has been selected. The 'grade' within the class will be determined by the physical properties required to yield a good sealing performance under the level of pressure in the service environment. Table 6 gives a guide to the level of properties required for various sealing pressure ranges. The actual material 'grade' will be determined in conjunction with the equipment supplier or on recommendation from TEAP. GUIDE TO PROPERTY LEVELS REQUIRED IN ELASTOMERS GRADES FOR VARIOUS SEALING PRESSURE RANGES Pressure Range Hardness (Shore A) Modulus Tensile Strength Elongation Compression Set Tear Strength Abrasion Resistance Impact Resistance Hysteresis Heat-up Extrusion resistance Blister Resistance

0 to 300 psi

300 to 3000 psi

> 3000 psi

60 -70 A Low Low - Med High Medium Low - Med Low - Med High Low - Med Low Low

70 - 85 A Medium Med -High Medium Low Medium Medium High Medium Medium Medium

> 85 A High High Low Low Low - Med High Med - Low Med -High High High

Table 6

2.10

PRACTICAL GUIDELINES

• The effect of a chemical reaction doubles for every 10°C temperature rise. The lifetime roughly doubles for every 10°C drop. • Make sure that the upper temperature is within the capability of the seal material. • The seal material must be compatible with the fluid environments. • Do not use Zinc Bromide (ZnBr) brine with Nitriles. • Be careful with Vitons if amine inhibitors are present. It may be better to use Aflas. • Methanol can affect Vitons. Use Aflas or Nitrile if possible.


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• Do not use EPDM where hydrocarbons are present. • For really aggressive, hot and sour conditions, the best choice is the expensive Kalrez (to 260°C) or Chemraz (20% cheaper and better properties over -20° to 230°C). • Pressure level dictates the mechanical properties required. • Critical pressure for blistering is Pb = 5E/6 where E = Youngs Modulus (at service temperature). • Critical pressure for rupture is Pr = 4(Lb x Sb)/3 where:

Lb = extension ratio at break (length of stretched material per unit initial length) Sb = stress at break (at service temperature)

• Consider use of T-seals with back-up rings if pressure exceeds 1500 psi, or pressure exceeds the modulus of the material. • Consider whether there is likely to be gas dissolved into the seal which may be subjected to rapid decompression. There are special grades with improved decompression resistance available. • Seal stacks form good solutions to wide ranging service. They allow use of varying hardness or differing materials in the stack, and the outer rings may be sacrificial for the sake of the main inner seal. • Elastomers with higher chemical and temperature resistance, e.g. Aflas and Kalrez, achieve this resistance often at the expense of elasticity. This compromises their ability to seal with temperature fluctuations. • In Static Seal Assembly seals (ie Solid Latch Anchor) Molded Seals are recommended instead of V-seals when important and frequent pressure reversals are expected at seal level.

2.11

REFERENCES


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NACE Standard MR-01-75-1988: ‘Standard Material Requirements for Sulphide Stress Cracking Resistant Materials for Oil Field Equipment’, National Association of Corrosion Engineers, Houston Tuttle, R N and Kane, R D: ‘H2S Corrosion in Oil and Gas Production - A Compilation of Classic Papers’, National Association of Corrosion Engineers De Ward, C and Milliams, D: 'Predietion of Carbonic Acid Corrosion in Natural Gas Pipelines', First International Conference on the Internal and External Protection of Pipes, University of Durham, 1975 Thomas, S, de Ward, C and Smith, L M: 'Controlling Factors in the Rate of CO2 Corrosion', UK Corrosion, 1 Q97 API Recommended Practice RP 14E: ‘Recommended Practice for Design and Installation of Offshore Production Piping Systems’, 4th Edition (April 1984)


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


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

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INDEX 3. TUBING DESIGN ............................................................................................................................3 3.1 INTRODUCTION .......................................................................................................................3 3.2 TUBING DESIGN OVERVIEW ..................................................................................................3 3.3 FACTORS INFLUENCING WELL COMPLETION DESIGN.......................................................4 3.3.1 RESERVOIR CONSIDERATIONS ..................................................................................4 3.3.2 MECHANICAL CONSIDERATIONS ................................................................................4 3.3.3 GENERAL CONSIDERATIONS .......................................................................................4 3.4 LITERATURE AND REFERENCE MANUALS...........................................................................5 3.5 TUBING SIZING ........................................................................................................................6 3.5.1 COLLECTION OF FLUID PROPERTIES .........................................................................6 3.5.2 COLLECTION OF RESERVOIR DATA ...........................................................................6 3.5.3 RESERVOIR - WELL SYSTEM ANALYSIS .....................................................................6 3.5.4 3.5.4 CALCULATION OF PRESSURE AND TEMPERATURE GRADIENT ....................9 3.5.5 PRESSURE DROP CORRELATIONS ...........................................................................11 3.5.6 DEFINITION OF THE COMPLETION STRATEGY.........................................................16 3.5.7 MATERIAL SELECTION ................................................................................................16 3.5.8 DOWNHOLE EQUIPMENT SELECTION......................................................................16 3.5.9 CHECK OF TUBING RESISTANCE..............................................................................16 3.5.10 CHECK OF PARTICULAR CONDITIONS: ...................................................................17 3.6 EFFECTS OF VARIABLES CHANGE ON THE PRESSURE GRADIENT CURVES ..............21 3.7 TUBING FEATURES ...............................................................................................................24 3.7.1 TUBING CHARACTERISATION ....................................................................................24 3.7.2 TUBING STEEL GRADES .............................................................................................25 3.7.3 TUBING CHECKS.........................................................................................................28 3.8 TUBING CONNECTION .........................................................................................................28 3.8.1 TUBULAR CONNECTIONS .........................................................................................28 3.8.2 CONNECTIONS DESCRIPTION....................................................................................29 3.8.3 THREADS ......................................................................................................................29 3.8.4 SEALS ...........................................................................................................................30 3.8.5 CONNECTIONS REQUIREMENTS ..............................................................................31 3.8.6 GENERAL CONNECTION SELECTION .......................................................................32 3.8.7 AGIP STANDARD JOINTS SELECTION CRITERIA ......................................................34 3.9 3.9 WELL MONITORING.........................................................................................................35 3.10 WELL COMPLETION DESIGN EXAMPLE: WAKAR FIELD.................................................36 3.10.1 INTRODUCTION AND TUBING STRESS ANALYSIS..................................................36 3.10.2 TUBING SIZE AND MATERIAL....................................................................................38 3.11 FIGURES AND TABLES LIST ..............................................................................................40


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The tubing design should characterize the minimum cost completion to efficiently produce the oil and/or gas of the reservoir for the expected life of the well. The optimum tubing design should also allow easy maintenance and minimum cost workover. The aim of this chapter is to introduce the tubing sizing criteria and tubing stress analysis method to define the proper tubing diameter. In fact, the tubing must be designed to prevent failures due to tensile force, internal and external pressure and corrosive actions.

3.2

TUBING DESIGN OVERVIEW

The procedure for tubing sizing is summarised in the following 8 steps. 1. Collection of fluid properties The available information should include, as a minimum: oil and gas gravity, water density and salinity, Gas Oil Ratio (GOR) and Water Oil Ratio (WOR). 2. Collection of reservoir data The reservoir data should provide the expected Flowing Bottom Hole Pressures (FBHPs) as a function of different flow rates (Qs). 3. Calculation of pressure and temperature gradient 4. Definition of the completion strategy From the calculation of the pressure gradient the well could result naturally flowing, i.e. FTHP > 0, or not flowing. If the calculated FTHP is lower than the required one by design constraints (required transfer pressure for flowline shipping) or the well is not naturally flowing, different operative conditions and/or different artificial lift options should be taken into account. 5. Material selection Suitable materials should be selected to avoid corrosion and/or erosion related problems. 6. Downhole equipment selection The following considerations should be taken into account. • Technological and/or Market availability • Operability of Wireline tools, Coiled tubing or other workover tools • Restriction to be verified for possible erosion 7) Check of tubing resistance The tubing should be checked against the maximum stresses expected throughout the expected well life (Ref. Tubing Stress Analysis, chapter 3). If the check fails, the sizing should be changed to an heavier tubing (reduced ID) or to a stronger material (better yield), or the design loads should be reduced. 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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8. Check of particular conditions • Gas slippage in case of high GOR and low pressure inside tubing for oil wells • Gas slippage in case of gas well in presence of liquid • Hydrate formation in gas wells in restriction.

3.3

FACTORS INFLUENCING WELL COMPLETION DESIGN

A reasonable estimation of the expected requirements is essential for an effective well completion design. However, it is difficult to predict the change of the operative conditions throughout the well life. The problem then becomes how to balance both capital and operating cost against the risk of tubing failure and/or the risk to face an unexpected workover. Some reservoir mechanical considerations are outlined here below.

3.3.1 • • • • • • •

RESERVOIR CONSIDERATIONS

Producing rate for maximum recovery Multiple layers produced by one well Secondary recovery Stimulation (acid or frac job) Sand control Workover frequency Artificial lift

3.3.2

MECHANICAL CONSIDERATIONS

• Tubing diameter for optimum well performance • Casing-tubing and tubing-surface interfaces • Tubing metallurgy for mechanical requirements and corrosion/erosion potential throughout the expected completion life • Connection selection • Review of tubing handling and connection make-up procedures • 3.3.3 GENERAL CONSIDERATIONS • Flexibility for maintenance and future requirement • Simple installation, both from equipment and procedural point of view, considering operator skill available • Safety as a must everywhere. In offshore, populated or isolated areas automatic shut-in fail safe and well pressure control methods should be included.


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LITERATURE AND REFERENCE MANUALS

The general reference and guideline is API Specification 5CT to ensure fitness for purpose and the required reliability, i.e. quality level and inspection requirements. API Bulletin 5C2 “Performance Properties of Casing and Tubing” contains detailed specifications for oil well tubular goods. API Bulletin 5C3 “Formulas and calculations for Casing, Tubing, Drill pipe and Line Pipe properties” contains detailed specifications for well tubular analysis. API Bulletin 5C1 “Care and Use of Casing and Tubing” contains recommended makeup torque for API connection and AGIP “Tubing Handling & Running Procedures” (Doc. STAP A1M-1003 dated 08.05.1995) refer to Company utilised material. The AGIP “Welcome manual” (Computerised Expert System reference manual) and the AGIP “Completion Design for Water Injection Wells” (document TEAP P1R-8506 dated 12 June 1995) are also the reference to design. Some particular cases of completion as for hostile or unusual conditions are not fully covered by API 5CT and by AGIP manual. These cases often require a more stringent specification and should be made under control of technical specialist of Agip Corrosion Dpt. (CORM) and Completion Dpt. (TEAP). In addition to the above guidelines, it is important to recognise that local or national statutory regulations in the country of operation must be complied with and these may impose additional or limiting requirements. General literature references for Well design are also: Thomas Allen & Alan Roberts, “Production Operations”, OGCI Dale Beggs, “Production Optimisation”, OGCI Dale Beggs, “Gas Production Operations”, OGCI


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TUBING SIZING

The starting parameter to sizing the completion tubing is the maximum production rate. The maximum production rate, in a defined well, depends upon the parameters below: • static reservoir pressure • inflow performance relationship • pressure drop in tubing • pressure drop through the wellhead constrictions • pressure drop through the flowline • pressure level required in the surface facilities 3.5.1

COLLECTION OF FLUID PROPERTIES

The available information should include oil and gas gravity, water density and salinity, Gas Oil Ratio (GOR) and Water Oil Ratio (WOR). Other useful data are the bubble point pressure, the dissolved gas (Rs) at reservoir conditions and the amount of H2S and CO2 in the produced gas. Please note that if a PVT study is available, the Flash Vaporisation Data should be used to calculate the tubing performance, while the Differential Vaporisation Data better describe the reservoir life.

3.5.2

COLLECTION OF RESERVOIR DATA

The reservoir data should provide the expected Flowing Bottom Hole Pressures (FBHPs) as a function of different flow rates (Qs). If FBHPs and the relevant Qs are available, the optimum tubing size can be easily found by calculating the Flowing Tubing Head Pressures (FTHPs). If FBHPs and Qs are not available, a Well Performance Study should be done. The Well Performance Study includes a Reservoir and a Tubing performance study and requires fit-forpurpose software run by specialists.

3.5.3

RESERVOIR - WELL SYSTEM ANALYSIS

The system composed by the reservoir plus the tubing, and where the various component are interactive can be analysed by nodal analysis. The first step is to selecting an appropriate division point (node). The most useful point is the lower end of the tubing in front of the perforating. All components upstream of this node compose the inflow section, and all components down stream the outflow section. The first step is to develop a relation between flow rate and pressure drop for each component in both sections. Flow rate for the specific system can be determined by satisfying the following relationships: 1. Flow into node = flow out of node 2. Only one pressure can exist at the node


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Generally in the normal well flow system two pressure are fixed: the average reservoir pressure and the separator pressure. The Reservoir Performance Study calculates the pressure drops in the reservoir by means of Darcytype equations. From the Darcy’s Law derives the Productivity Index (PI) that is a relationship between Q, the well inflow in this case, and the reservoir drawdown (∆P): PI = Q / (SBHP - FBHP) = Q / ∆P On the other hand, the Tubing Performance Study calculates the pressure drop in the tubing string and in the surface equipment by means of Bernoulli-type equations or empirical correlations. The general pressure gradient equation, which will apply to flow of any fluid in a pipe at any inclination angle, is given by following equation:

dp = ρg sinθ + fρv2 + ρvdv dL gc 2gcd gcdL This equation is written as composition of the three terms of the following equation:

(dp/dL)total = (dp/dL)el + (dp/dL)f + (dp/dL)acc More explanation about that will be given at paragraph 2.5.5. The Well Performance Study, that links the Reservoir Performance with the Tubing performance, provides plots like the one shown in Figure 2.1. Curve “A” is the inflow (Reservoir) performance. The inflow performance intercept of the Y-axis is the SBHP, the intercept of the X-axis is the Absolute Open Flow (AOF), i.e. the theoretical production rate at zero flowing tubing head pressure, and the initial slope is the PI.


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Figure 2.1: Inflow and outflow performance diagram

Inflow-Outflow performance diagram

P [kg/cm2] 600

SBHP “A” “B” 400

300

(FTHP = fixed)

“P”

(FBHP)i

100

MIN unstable flow 0

100

200

300

(Q)i

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AOF Q [m3/d]

Curve “B” is the outflow (Tubing) performance. If the fluid inside the tubing is single-phase, i.e. oil or water or gas, the calculation of the pressure drop is relatively easy. In presence of two-phase flow, e.g. oil and gas mixture, the fluids could separate because of the difference in density and velocity (gas slippage) so that it is difficult to determine an overall density, viscosity, and velocity. To determine the fluids properties and the pressure drop in the tubing, a number of empirical correlations is available. The best correlation can be selected by fitting production (or injection) test data and/or by PVT analysis.


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The intersection of inflow and outflow performance is the operating point “P” of the whole production system. Given a fixed value of FTHP, the operating point defines the FBHP on the Y-axis and the relevant Q on the X-axis at the considered node. Finally, the outflow performance at the right-hand side of the minimum defines all possible operating points, i.e. possible values of Qs and relevant FTHPs, while all the points at the left-hand side of the minimum indicate situations of unstable flow.

3.5.4

3.5.4

CALCULATION OF PRESSURE AND TEMPERATURE GRADIENT

The pressure gradient should be calculated with the reservoir data and the fluid properties starting from the bottom hole. Some special applications can require the calculation of the temperature gradient. The calculation should be repeated for all expected flow rates or at least for the boundary conditions, e.g. the maximum Q, the maximum Water Cut (WC), the maximum GOR rate, FTHP. A rough tubing size selection, or the first tentative choice, can be done by using the following table.

Table 2.1: Producible oil and gas rate range Vs tubing size

Tubing size [inches]

weight [lb/ft]

I.D. [inches]

2 3/8 2 7/8 3 1/2 4 1/2 5 1/2 7.0

4.6 6.4 9.2 12.6 17.0 29.0

1.995 2.441 2.992 3.958 4.892 6.184

OIL RATE RANGE [m3/d] <150 150 - 500 300 - 1000 500 - 1600 800 - 2700 >1200

DRY GAS RATE RANGE [km3/d] <50 50 - 250 80 - 400 180 - 1000 250 - 1500 400 - 4000

Note that values in Table 2.1 are only indicative because there are a number of variables that can affect the flow-rate: tubing length, FBHP, Absolute Tubing Head Pressure (ATHP) especially for gas wells, water content, liquid viscosity, or also the expected future operative condition, e.g. artificial lift or increase of WC in gas wells.


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Figure 2.2: Pressure gradient plot (production and injection) Fluid Pressure - Tubing/Workstring 0

2500

5000

TVD (ft)

7500

10000 Displace to brine Pull workstring/run tbg Initial production Shut-in #1 Acid job Produce 1 year Shut-in #2 Post-prod acid job Shut-in #3

12500

15000

17500

20000 0

4000

8000 Pressure (psig)

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PRESSURE DROP CORRELATIONS

The general pressure gradient equation, which will apply to flow of any fluid in a pipe at any inclination angle, is given by following equation:

dp = ρg sinθ + fρv2 + ρvdv dL gc 2gcd gcdL where: ρ = fluid density g = gravity acceleration gc= reference gravity acceleration θ = inclination angle f = friction factor v = average fluid velocity This equation is written as the composition of the three terms in the following equation:

(dp/dL)total = (dp/dL)el + (dp/dL)f + (dp/dL)acc The range of contribution of each of these components to the total pressure drop in the well can be seen from the following table, where the contributions are listed as percent of total ∆p in the tubing, pwf - pwh, for both oil and gas wells.

Table 2.2: Pressure drop terms contribution Component Elevation (Hydrostatic) Friction Acceleration

Percent of Total ∆p Oil Wells Gas Wells 70 - 90 20 - 50 10 - 30 40 - 60 0 - 10 0 - 10

The density of the fluids in oil wells is usually much greater than for gas wells, and since the hydrostatic component depends on liquid hold-up, this is the most important parameter that must be evaluated. In gas wells, the fluid density is smaller, but the gas is usually moving at a relatively high velocity, which generates more friction loss in the pipe. This necessitates having a good value for pipe roughness from which to obtain a friction factor. Many correlations have been developed in the last 30 or 40 years for predicting two-phase flowing pressure gradients in producing wells. A list of the many methods and a brief review of each can be found in Brown. Some investigators chose to assume that the gas and liquid travel at the same velocity so that the mixture density can be calculated based on the no-slip liquid hold-up λL. No methods presently exist for analytically evaluating either liquid hold-up or friction factor. Therefore, it has been necessary to develop empirical correlations for these two parameters as functions of variables that will be known or can be calculated from known data.


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1. Establish state flow conditions at particular values of Ql (liquid flowrate), Qs (total flowrate), pipe I.D., pipe angle, etc. 2. In a test section of length ∆L, measure HL (liquid ratio) and ∆p. Methods for measuring HL include nuclear densitometers, capacitance devices, quick closing valves, etc. Flow pattern may be observed if the test section is transparent. 3. Calculate mixture density and elevation component.

ρs = ρLHL + ρg( 1 - HL ) (dp/dL)el = ρg sinθ gc 4. Calculate an acceleration component (if it is to be considered) and the friction component.

(dp/dL)f = (∆p/∆L) - (dp/dL)el - (dp/dL)acc 5. Calculate a two-phase friction factor

fTp = 2gcd (dp/dL)f ρv2m 6. Change test conditions and return to Step 2. HL, fTp and flow pattern should be obtained over a wide range of conditions. 7. Develop empirical correlations for HL, fTp and perhaps flow pattern as a function of variables that will be known for design cases. These variables include vsL, vsg, d fluid properties, pipe angle, etc. Many authors have developed mathematical correlation and method to calculate the pressure drop, some of these are: • Poettmann and Carpenter It is the first serious attempt at solving the multiphase well flow problem. It was developed using measured field data from 334 flowing wells and 15 continuous flow gas lift wells. The wells producing through tubing sizes ranging from 23/8” to 3½”. The production rate were less than 500 STB/day at GLR’s less than 1500 scf/STB. This method, although easy to apply, will give erroneous results when applied to wells that are not producing under condition very similar to those from which the developing data were obtained. • Hagedorn and Brown The method was developed by experimental pressure drop and flow rate data from a 1500 ft deep instrument well. Pressure were measured for flow in tubing size ranging from 11/4“ to 27/8”. A wide range of liquid rates and gas/liquid ratios was included, and the effects of liquid viscosity were studied by using water and oil as the liquid phase. The oil used had viscosity at stock tank condition of 10, 35 and 110 cp. The method has been found to give good results over a wide range of well 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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• Duns and Ros The authors performed an experimental study of vertical two-phase flow in laboratory. The experiment, which consists of 4000 run and 20,000 data points, was conducted at low pressure using air, oil and water as the fluids components. The test section was 10 m long and the pipe diameters ranged from 3.2 cm to 8.2 cm. Some annular flow tests were also conducted. Three flow patterns were defined, and a flow patterns map was constructed from which the flow pattern can be determined based on the superficial velocities of the liquid and gas phases. The flow patterns are described as follows: 1. Bubble flow pattern: the liquid phase continuous, the gas phase moves as discontinuous bubble or plugs. 2. Slug flow pattern: both liquid and gas are discontinuous. 3. Mist flow pattern: the gas phase is continuous and the liquid moves as droplets dispersed in the gas or in the annular ring around the inside the pipe. The method is considered to be applicable over a wide range of well conditions. • Orkiszewski The author performed a comparison study on some 148 measured well conditions and found that none of the correlations existing at that time (1967) adeguately predicted the measured results. He than used the data of Hagedorn and Brown and the field data from 148 well conditions to develop a new correlation to be used in the Bubble and Slug flow patterns. He recommended using the Duns and Ros method for Mist flow. The flow patterns considered are: Bubble flow, Slug flow, Transition flow, Mist flow. The method is applicable over a wide range of well conditions, but in some cases, a mixture density less than no-slip density will be calculated. Also, discontinuities in the calculated pressure traverse (gradient) can occur as the mixture velocity exceeds 10 ft/s. This results from changing equations for mixture density at this velocity. • Beggs and Brill This correlation was developed from experimental data obtained in a small scale test facility: 0” and 1.5” sections of acrylic pipe 90 ft long. The pipe could be inclined at any angle. The parameters studied and their range of variation were: 1.- gas flow rate 0-300 Mscf/d 2.- liquid flow rate 0-30 gal/minute 3.- average system pressure 35-90 psi 4.- pipe diameter 1-1.5” 5.- liquid hold-up 0-0.870 6.- pressure gradient 0-0.8 psi/ft 7.- inclination angle -90° to +90° 8.- horizontal flow pattern The method can be applied to a flow in a pipe at any angle of inclination, including downward flow. Although the method has been found to predict the pressure gradient in vertical wells, in some cases, it gives good results for pipeline calculation.


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At the next page, Table 2.3, resumes the most known correlations with some notes and the applicability field.

TABLE 2.3: APPLICABILITY OF PRESSURE LOSS PREDICTION METHODS Method

Years

Type

Accuracy

Data Type

Fluids

Duns and Ros

1963 Flow Pattern Dependent

Good

Laboratory, experimental plus field data

Oil, Water, Gas

Hagedorn and Brown

1965 Slip Flow

Good ( in some flow patterns )

Field experimental

Oil, Water, Air

Good

Field experimental

Oil, Water, Air

Some Hagedorn and Brown Data, Field

Oil, Water, Gas

Hagedorn and Brown

Flow Pattern Dependent

Orkiszewski

1967 Flow Pattern Dependent

Fair

Aziz et al

1972 Flow Pattern Dependent 1973 Flow Pattern

Variable Laboratory and Oil, Water, depends on Field Gas version Poor Laboratory Air, Water

Beggs and Brill

Applicability and Comments Conservative. Tends to overpredict pressure drop. Good predictive method where several flow patterns are present Does not predict a correct TPC minimum. Poor in bubble flow. Liquid hold-up prediction can be less than for noslip flow. Should be used with caution. Optimistic. Tends to underpredict pressure drop. This is the preferred correlation in the absence of other data. Conservative, Tends to overpredict pressure drop. Can cause convergence problems in computing algorithm Optimistic. Tends to underpredict pressure drop. Developed for deviated wells but tends to significantly


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TABLE 2.3: APPLICABILITY OF PRESSURE LOSS PREDICTION METHODS

Beggs and Brill with Palmer

Flow Pattern Dependent

Fair

Laboratory

Air, Water

overpredict pressure drop. Should be avoided unless well is highly deviated (>45°) Developed for deviated wells but tends to overpredict pressure drop.


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3.5.6 DEFINITION OF THE COMPLETION STRATEGY From the calculation of the pressure gradient the well could result naturally flowing, i.e. FTHP > 0, or not flowing. If the calculated FTHP is lower than required by design constraints or the well is not naturally flowing, different operative conditions and/or the artificial lift options should be taken into account.

3.5.7 MATERIAL SELECTION Suitable materials should be selected to avoid corrosion related problems. Three options are available within Agip: 1. refer to the Corrosion Dept. (CORM), if the conditions are severe or not-standard 2. refer to tables in the literature 3. refer to Welcome Expert System criteria already mentioned in previous paragraph of this volume.

3.5.8

DOWNHOLE EQUIPMENT SELECTION

The following considerations should be taken into account. 1. Downhole technological and/or market availability 2. Operability of Wireline tools, Coiled tubing or other workover tools 3. Restrictions to be verified for possible erosion For erosion, the reference is the following API formula that provides the maximum safe fluid velocity [ft/sec]:

vmax = C / (√ρ) where ρ is the mixture density [lbm/ft3] and C is an experimental constant. Based on AGIP operating experience and test data from manufacturers, currently recommended C factors for various materials are as follows: • Carbon steel : 100 • 13%Cr stainless steel : 200 • Duplex stainless steel and over: 250 The erosion is critical for water injection wells and for gas wells with possible presence of sand or fines.

3.5.9

CHECK OF TUBING RESISTANCE.

The tubing should be checked against the stresses expected throughout the expected well life (Ref. Tubing Stress Analysis chapter 3). If the check fails, the sizing should be changed to an heavier tubing or to a stronger material, or the design load should be reduced.


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3.5.10 CHECK OF PARTICULAR CONDITIONS: 1.- Gas slippage in case of high GOR and low pressure inside tubing for oil wells 2.- Gas slippage in case of gas well in presence of liquid (water or condensate); in this case a minimum velocity of the gas is required to remove the liquid. Compare the range of producible rates in table at point 3) with the minimum rate function of tubing size and tubing pressure, see Figure 2.3. Figure 2.3: Prediction of minimum gas flow rate required for liquid removal (not to scale) PREDICTION OF MINIMUN GAS FLOW RATE REQUIRED FOR LIQUID REMOVAL FROM GAS WELLS

TUBING PRESSURE psi

MINIMUM FLOW RATE MM cu.ft/day

TUBING I.D. in.

100 10 10000

5000

10 5

3000 1000

4

2000 3 1000

Water scale

Condensate scale

1

1

2

100

0,1 1 100

The nomogram (ref.: ASME TRANS. (1969) vol. 246 page 1475) should be used as follows. Starting from the tubing pressure value on the left-hand axis draw a line to the tubing diameter on the right-hand axis. The central axis then displays the minimum gas flow rate required to remove the liquid fraction.


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3.- Hydrate formation in gas condensate wells can occur in restrictions of the tubing string or/and across the surface choke. An approximated evaluation can be made by using diagrams like one in figure 2.4. (In the diagram in figure 2.4 the starting point is the initial pressure (on Y-axis); moving horizontal when crossing the curve related to the temperature of the fluid in that point allows to evaluate the minimum pressure downstream of the restriction to avoid hydrates formation). Note that the available diagrams are referred in general to natural gas (methane) but the presence of H2S and/or CO2 increase the hydrates temperature and reduce the pressure above which hydrates form.

Figure 2.4: Permissible expansion of a 1.0 gravity natural gas without hydrate formation


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4. A possible failure damage must be considered in terms of economic cost, workover complexity, environmental impact, workers and people injuries.

The final result of tubing sizing is the pressure (and sometimes also temperature) gradient throughout the expected well life. An example is shown in figure 2.5, where every curve is related to an operative condition in a given year of the well life.

Figure 2.5: Pressure (fig. 2.5A) & temperature (fig. 2.5B) gradient for production well Figure 2.5A BALTIM South: FLUID PRESSURE GRADIENT VERTICAL WELL - FLUID GAS - TUBING 3.5" CASE COMPARISON

0

DEPTH [m]

-1.000

-2.000

-3.000

-4.000 180

200

220

240

260

280

300

320

340

PRESSURE [kg/cm2] Prod.200km3d Prod.50km3d Prod.500km3d Prod.300km3d Prod.250km3d Water340m3d Water300m3d Water=0 Water=0 Water=0


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Figure 2.5B BALTIM South: FLUID TEMPERATURE GRADIENT VERTICAL WELL - FLUID GAS - TUBING 3.5" CASE COMPARISONS 0

DEPTH [m]

-1.000

-2.000

-3.000

-4.000 0

20

Undisturbed

40

60 TEMPERATURE [°C]

80

100

120

Prod.250 km3d Prod.300 km3d Prod. 500 km3d Prod. 50km3d Prod. 200 km3d Wc = 0 Wc = 0 Wc = 0 W300m3d W340m3d


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3.6

21

EFFECTS OF VARIABLES CHANGE ON THE PRESSURE GRADIENT CURVES

The next figures show the effect of single parameter change. Figure 2.6 shows the tubing sizing effect on the pressure gradient curves, figure 2.7 shows the GLR effect, figure 2.8 shows the flow rate increasing effect, figure 2.9 shows the oil gravity increasing effect and figure 2.10 shows the viscosity effect on pressure gradient.

Figure 2.6: Tubing size effect on the pressure gradient curves

0

1

2

4

5

Tu bi

Depth, 1,000 ft

3

ng

6

siz e 1 in

7

.

1 1/

8

4 in .

. 3 in

n. 2i

9

10 0

5

10

15

20

25

30

35

Pressure, 100 psi


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Figure 2.7: GLR effect on the pressure gradient curves 0

1

2

G

3

L R cf /s tb ) 0

5

20

Depth, 1,000 ft

(s

4

0

6

50

7

0

8

1, 50 0

9

10

0

4

8

12

16

20

24

28

Pressure, 100 psi

Figure 2.8: Flow rate increasing effect on pressure gradient 0

1

2

4

5

q

Depth, 1,000 ft

3

(s

6

tb /d ) 2,

7

00 0

1,

8

00 0

20

9

0

50

10

0

5

10

15

20

25

30

35

Pressure, 100 psi


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Figure 2.9: Gravity increasing effect on pressure gradient 0

1

2

Depth, 1,000 ft

3

4 Brine water µw = 1.07 5 Fresh water µw = 1.07 6 API gravity = 10 7 API gravity = 50 8

9

10 0

5

10

15

20

25

30

35

Pressure, 100 psi

Figure 2.10: Oil viscosity effect on pressure gradient 0

1

2

De ad

4

oi .2

ity

16

os

p-

isc

0c

lv

50

5

PI

o isc nt v

7

°A

3.0 -2

sta

6

50

con

Depth, 1,000 ft

3

sity 1.0 cp

8

AP 5° -3

9

I

10 0

4

8

12

16

20

24

28

Pressure, 100 psi


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TUBING FEATURES

3.7.1 TUBING CHARACTERISATION Tubing consists of non-welded pipes which are run into the well, and made up one on top of the other until the desired depth. The parameters characterising the tubing are listed below. Nominal diameter, Outside Diameter (OD) All well tubulars follow the API specifications in standardising on outside diameter. Hence, 4½” tubulars have an OD of 4½”. In addition, API defines tubing as having an OD from 11/20“ to 4½” . Tubulars with OD of 4½” or greater are classified as casing. Length Range (R) Tubulars are manufactured in lengths termed 'joints'. The API specification only allows tubing joints to be manufactured in two length ranges. However, some mills can produce Range 3, and, where practicable and possible, this range is preferred. • Range 1: 20 to 24 feet • Range 2: 28 to 32 feet • Range 3: 32 to 48 feet The API casing standard allows three ranges, namely: • Range 1: 16 to 25 feet • Range 2: 25 to 34 feet • Range 3: 34 to 48 feet Permissible maximum variation is 2 ft either for range 1 or range 2. Weight per Foot (Ib/ft) The ability of a tubular to withstand stress is governed by its mechanical strength (grade) and wall thickness. Since API standardises tubulars on OD, an increase in wall thickness decreases the inside diameter (ID) and obviously increases the weight. Tubulars are therefore specified in terms of OD and weight of pipe per linear foot. However, some suppliers do exceed API tolerances on OD in order to minimise the reduction in ID. The API specifies a limited number of standard weights for any particular tubular size. However, non-API heavy walled tubing is also available for high strength applications. These tubulars have proprietary grades, and the stress analysis should be discussed in detail with the individual manufacturer. Drift ID It is important that all production/completion tubulars are drifted in accordance with AGIP recommendation. This should allow the safe passage of any equipment and will ensure injection and production rates are not impeded.


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3.7.2 TUBING STEEL GRADES

The oilfield technicians do not use very often the international recommended nomenclature for steel. Standard API steel grades are designed by a capital single letter and a number (two figure). The letter indicate general characteristic of steel, but generally these letters have very little relevance in determining the physical properties of the tubular. The number indicate the minimum yield strength expressed in thousand pound per square inch. Sometimes the manufacturers indicate by themselves with meaningful letters (two) the steel grades and generally with the number indicating the minimum yield strength in thousand p.s.i. Hence there are effectively the same pipe, but with a different designation: in any case the API reference, whiles for CRA tubulars, is the reference one.

The figure of a steel is important since it provides information as to the minimum tensile properties of the pipe and is also a function of most of the pipe's other physical properties, i.e. burst and collapse. It should not be confused with the ultimate tensile strength (UTS), which is not used in pipe identification. The minimum yield stress value is used in all tubular stress analysis. API standard grades are listed below and the designations indicate minimum yield strength in 1000 psi and the grade of new pipe can be identified by colour bands as follows: J-55 green band C-75 blue band N-80 red band P-105 white band

K-55 L-80 C-95

two green bands red with brown band brown band

The standard API steel grades and the tensile requirements for tubing are : Yield strength (psi) minimum maximum H-40 J-55 K-55 L-80 N-80 C-90 C-95 T-95 P-110 Q-125

40,000 55,000 55,000 80,000 80,000 90,000 95,000 95,000 110,000 125,000

80,000 80,000 80,000 95,000 110,000 105,000 110,000 110,000 140,000 150,000

Tensile strength (psi) minimum 60,000 75,000 75,000 95,000 100,000 100,000 105,000 105,000 125,000 135,000

Standard API steel grades for tubing type L and T are intended for hydrogen sulphide (H2S) service, they are heat treated to remove martensitic crystal structure; with L grade hardness must not exceed 23 Rockwell C. CRA materials are at the not covered by API standardisation. They are identified by suppliers name and same definition of yield in 1000 psi. 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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CRA materials are less homogeneous than carbon steel and suffer of higher tensile characteristics versus temperature. In the next two figures there are shown the temperature variations of the Yield strength, the Tensile strength and of the Elongation for Sumitomo C.R.A. 25%Cr, 75,000 psi and Sumitomo 13% Cr Super Martensitic, 95,000 psi.

Figure 2.11: Tensile properties of Sumitomo 25%Cr 75 ksi steel

Tensile properties at elevated temperature of SM 25CR-75 Temperature °C 100

0

200

120 900 TS

100

YS, TS (MPa)

YS, TS (ksi)

700

YS

80

500 60

EI. (%)

40

20

RT 100

200

300

400

500

Temperature (°F)

Figure 2.12: Tensile properties of Sumitomo 13%Cr 95 ksi supermartensitic steel


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Tensile properties at elevated temperature of SM 13CRS-95 Temperature °C 100

0

200

130 900 TS

110

YS, TS (MPa)

YS, TS (ksi)

700 YS

90

500 70

EI. (%)

40

20

100

200

300

400

Temperature (°F)


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3.7.3 TUBING CHECKS Before using tubing for completion it is advisable to carry out various checks, to make sure they are in good condition. There are electromagnetic methods to spot transverse and longitudinal defects due to construction, such as rolling scales, cracks etc. However, these are applied only to the pipe body. To note cracks in the threaded parts, in the couplings or in the upsetting, magnetic-optic system are used. We use iron powder sprinkled on the parts concerned which are then immersed in a magnetic field and helped by a Wood lamp. Ultrasonic systems are also used especially when internal defects or exact thickness are to be checked. Generally above inspections are made in the mill as part of the Quality Plan associated with each order.

3.8

TUBING CONNECTION

There are two API standard connection available: • Non Upset • External Upset The API Non Upset tubing connection (NU) is a 10-round thread form, wherein the joint has less strength than the pipe body. The API External Upset tubing connection (EUE) is an 8-round thread form wherein the joint has greater strength than the pipe body. API EUE connections are available also for very high pressure service having a long thread form (50% longer than standard) API couplings extra clearance can be turned down without loss of joint strength. Special clearance collars are usually marked with a black ring in the centre of the colour band indicating the steel grade. For small diameter tubing it has been developed an Integral connections, 10-round thread form. Generally speaking, AGIP never use API connections, unless for ESP (Electrical Submersible Pump) or Sucker Rod Pump applications, where the wells are not normally flowing to surface. Same connections, in a very precise moulding, are used to connect “Fiberglass tubing” which for installation in limited load conditions can be conveniently used as economic alternative to CRA pipe. 3.8.1

TUBULAR CONNECTIONS

Machined threads at the end of the tubulars allow joints to be assembled into strings. These threaded connections must provide pressure integrity and have sufficient strength to withstand the tubing body stresses. The API specifications only apply to API tubing and casing connections and do not apply to the nonAPI proprietary connections like VAM. Non-API contentions sometimes termed premium connections, have been designed to overcome some of the limitations in the API equipment, including: • Providing greater axial strength. • Smaller connection OD. • Improved pressure integrity (gas tight sealing).


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3.8.2 CONNECTIONS DESCRIPTION Tubular connections are like complex pressure vessel closures in that they are required to maintain structural integrity and gas/fluid saleability. The structural integrity of these connections is accomplished by the: • Threads. • Seals. • Shoulders. There are three main types of connections listed in order of structural performance. They are: • Integral upset. • Threaded and coupled. • Flush joint. Integral upset tubulars, e.g. Hydril (CS, PH6), are manufactured from one piece of pipe. They are similar in appearance to drillpipe, but are far superior in terms of structural performance. The connections in threaded and coupled tubulars are manufactured from the same materials as the pipe body. Flush joint connections are also manufactured from one piece of pipe. However, due to the design of the connection (internally and externally flush), it does not possess the same strength as either the integral upset or the threaded and coupled connection. Each connection type has its applications, depending on the conditions. The design of a tubular connection is similar to other machine design processes. Design of tubular connections is based on the following simplifying assumptions: • The material is ductile. • Service loads are applied statically. In other words, service loads are neither dynamic or applied by impact. • Service temperature neither exceeds the creep range (about 600°F (316°C)) nor falls below the null ductility transition temperature (below about 4°F (-20°C)) under load conditions. Typical loading conditions that affect structural integrity of connections are tension or compression, internal or external differential pressure, surface and production temperature and corrosion. For helical buckled tubing and in high angle directional drilling, bending must also be considered. The same loading conditions also affect sealing integrity of connections, but in different ways. For example, axial tension can break, pull-out or jump-out a connection by exceeding its structural strength. It can also cause leakage of some connections by plastically deforming threads or reducing the contact bearing pressure of the sealing surfaces. Therefore, tubing designers more often desire tensile strength greater than pipe body in order to avoid distortion of seals.

3.8.3 THREADS Any thread form has basic features that include height (depth), stab flank angle, load flank angle, root radii, crest radii and surface finish. All threads follow a helix, whether cylindrical or tapered, and so possess pitch and lead. Threads are then matched to opposing threads with either precise interference, clearance or a combination of both. There are many different types of connections and thread variations that have been marketed. However, the basic thread forms in use today may be classified as: • 8-round thread forms • Buttress thread form • Shortened (stub) ACME thread form 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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• Reversed flank thread form Tubular connections in the past have utilised sharp V thread forms. Line pipe and bolts and nuts still use this thread form. The thread form offers adequate performance on non-upset pipe for oil wells ranging in depths up to 5000 ft.

3.8.4 SEALS 3.8.4.1 THREAD SEALS API 8-round and Buttress are typical of connections that depend on thread seals. The connection is designed in such a manner that when threads are assembled, the annular clearance between mating crest and root is a crescent-shaped space having a nominal 0.003 in clearance. With proper thread compounds which must plug this annulus, the joint is capable of performing an adequate control for leak resistance, provided appropriate torque is applied to the connection. Thread compound sealability is a function of application procedure, temperature and time. The grease base of API modified thread compound (75% content by volume) is the greatest limitation of 8-round threads. It can react with cleaning solvents, condensates, carbonic acid, hydrogen sulphide and ethane. It dries out with temperature and time, decreasing its resistance to the flow of gases or condensate. A suggested upper limit of temperature is approximately 210°F for long term applications. API modified compound is 67% metal filler by weight. It is possible to increase leak resistance by minimising clearance between mating thread elements. This may, however, cause thread wear or galling where service requirements include repeated make-up.

3.8.4.2 PLASTIC (ELASTOMERIC) SEALS This type of connection relies on a Teflon seal ring in the groove between mating surfaces. The ring is free to expand or contract with temperature in the direction of fluid flow, so that the metal connector walls are not significantly stressed by thermal effects. The seal materials have, in general. thermal coefficients of expansion that are several times that of steel. High flowing temperatures can create enough expansion pressure from the Teflon to separate pin and box threads and extrude the edges of the ring from its groove. Upon cooling, the seal ring contracts, but its shape has changed, and it is no longer tight in its groove. A loose seal ring can result in leakage. Experience to date (mainly in the USA) has shown that plastic seals are satisfactory up to 7500 psi. Above this, metalto-metal seals should be utilised. However, in the North Sea and in the rest of the world, metal-tometal seals are predominantly used above 5000 psi. Plastic seals (Corrosion Barrier, CB ring) have been used by Agip and qualified in Special Premium Joint connections to be applied to Internally Plastic Coated Tubing.

3.8.4.3 METAL-TO-METAL SEALS Metal-to-metal seals are of either shouldering type, sliding (flank) type or a combination of the two. The two types of metal-to-metal seals depend on a designed interference for the initiation of the sealing interface during assembly. The sliding sealing elements may consist of a curved surface pin seal mating to a conical female seal surface. The purpose of the curved seal is to concentrate the radial interference force to ensure an intimate contact with the female (box) member of the


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connection. Shouldering metal seals, like VAM, utilise mostly compressive axial strain to maintain the sealing interface. Metal-to-metal seals have proved to be not only reliable, but also durable. These independent sealing elements have been used on various products and subjected to practically every conceivable type of service in oil and gas completions. As long as the metal-to-metal seal coupled or integral joint casing or tubing is not pulled onto yield, not over torque, and handled with care, they offer high temperature, high pressure and gas tight performance. Depending on the joint material used, they may be almost indestructible as far as wear or galling after repeated use is concerned. However, they are least capable of field repair and cost the most to make and gauge.

3.8.4.4 PRESSURE ENERGISED METAL-TO-METAL SEALS Pressure energization refers to an increase in contact pressure at the sealing interface that is caused by an increase of pressure of the fluid being sealed. A pressure energised seal can utilise relatively low contact stress to initiate the sealing interface because the contact pressure increases at a greater rate than the fluid pressure.

3.8.4.5 SURFACE FINISH TOPOGRAPHY Surface finish topography is an important factor controlling fluid sealability. Smooth surfaces tend to permit 'channelling' through the lubricating film between the surfaces. Surfaces having roughness greater than 32 microinch, appear to trap lubricant in the surface discontinuities which act somewhat like a gasket with a multitude of tiny high points breaking up continuity of lubricating film, thus preventing channelling. A good surface roughness range for seal finishes was found to be from 32 to 125 microinch

3.8.4.6 SHOULDERS The principal function of the shoulder in the sealing mechanism is to absorb and retain the load generated by the torque. This is commonly referred to as a pre-load and is extremely important when energising the metal-to-metal seal in premium connections. Other types of shoulder are referred to in various proprietary connections, and these are commonly used as 'land-off' shoulders and assist the seal shoulder. These shoulders do provide some interference and some assistance in sealing. However, despite manufacturers' claims, this should not be considered as a reliable seal.

3.8.5

CONNECTIONS REQUIREMENTS

Depending on application, a connection may have to satisfy all or some of the following requirements: • Sufficient joint strength. • Adequate sealing force. • Resistance to damage when re-run. • Resistance to galling. 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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• Quick and easy make-up. • Smooth ID transition. A connection has to maintain sufficient structural integrity and resistance to leakage over all the applied service loads, including fracking, workovers, drilling bridge plugs etc. Most premium connections have better structural properties than the pipe body, although this should be confirmed with either a tubing specialist or the manufacturer.

3.8.6

GENERAL CONNECTION SELECTION

3.8.6.1 INTRODUCTION Selection of the appropriate connection should be based on the following factors: • The intended application for which the connection will be used. • The performance capabilities of the connection in its intended application. • Availability to location. Refurbishment and re-threading facilities for used pipe. • Cost. • Local Government requirements/constraints. The drilling or production engineer should procure connections from reputable manufacturers, ensure protection for connectors through all stages of inspection, storage and shipment and verify final integrity of assembled connections during field handling, running and testing. Unfortunately, the user faces a difficult task in selecting a connection for the particular size, weight and grade suitable for the intended application for the following reasons: • A large number of candidate connections that at first sight would appear to meet the downhole requirements. • The connection industry often rates its connections nominally, rather than on minimum dimensions and minimum strength values. • Often, little or no data is available to support the manufacturer's performance claims.

3.8.6.2 CONNECTION TYPES Production casing traditionally consists of production liners, production and tie-back casing. The primary attribute of production casing connections is their ability to withstand all well conditions without leaking or parting. Production casing and tubing connections must contain production fluids, and therefore require high sealing capability. Sealing requirements differ for liquids, steam and gas/ condensates. Long-term gas or condensate sealing at high temperature can only be accomplished with metal-to-metal or plastic seals. With the progress of technology and scientific improvements in material and product design, a variety of connections are now available for critical service applications. The thread compound in connections that rely on thread seals, is susceptible to deterioration with temperature and time and to corrosive degradation. Plastic seals can extend the sealing range up to 375°F. Metal-to-metal seals extend the sealing range further up to 650°F.


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For production casing, five generic connections are normally used: • API 8-round (STC or LTC). • API Buttress (BTC). • Metal-to-metal seal, formed and integral (flush) (IFJ). • Metal-to-metal seal, threaded and coupled (MTC). • Metal-to-metal seal, upset and integral (or coupled) (MIJ). STC and LTC are acronyms for short and long thread coupled, respectively. The API connections for production casing may or may not have plastic seals. Three generic tubing connections are normally used on production tubing: • API 8-round (EUE). • Metal-to-metal seal, threaded and coupled (MTC). • Metal-to-metal seal, upset and integral (or coupled) (MIJ). EUE is an abbreviation for externally upset end tubes. The API connections on production tubing may or may not incorporate plastic seals. API EUE is the basic tubing connection. The premium/non-API connections usually incorporate a metal-to-metal sealing. Premium connections provide extensive improvements in comparison to the above standard connections in: • • • •

Pressure ratings. Tensile capacity. OD clearance. Gas and fluid sealability.

The other improvements that are less frequently required include: • Controlled assembly stress. • Smooth ID transition. • Use of internal plastic coatings. API BTC that run out on the pipe OD, provide the greatest possible tensile resistance for connections on plain (non-upset) end pipe, with some loss of sealability. Upsets provide additional metal from which greater tensile capacity can be achieved, in excess of the pipe body capacity. This is important when pulling casing beyond its tensile overpull rating or pulling tubing beyond its yield point. It ensures that seals and threads are not distorted plastically and subsequently leak. Providing the metal-to-metal seal coupled connection is not pulled to yield, over-torqued and is handled with care, it will provide a reliable seal. Flush type connections are designed to maximise clearance downhole, requiring that tensile efficiency be sacrificed. However, such connections are usually run as shorter strings that do not require full pipe body tensile efficiency. Flush connections without cold-formed ends can only meet full pipe body internal pressure ratings when the thread is designed for the specific weight of pipe, and the thread and pipe OD are not eccentric. Therefore, fully internal pressure rated flush connections are normally cold-formed. Boxes are expanded to ensure adequate wall thickness over the primary seal. Pins are swaged (nosed down) and bored to ensure uniform deformation of the pin during assembly.


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AGIP STANDARD JOINTS SELECTION CRITERIA

The connections indicated by Welcome Expert System are all Premium type, for Agip standard the API connections are not considered. In the Welcome Expert System the available connections are collected in a data base where they are grouped in Coupling connections and Integral connections. Agip Standard Dpt. qualified the connections (see doc. STAP M1M-5006) and they are: Coupling :

Integral :

AMS 28 (manufacturer Dalmine) VAM ACE (manufacturer Vallourec and Sumitomo) Agip A-DMS (Agip Dual metal seals)

The Hydril PH-6 and the PJD Dalmine connections are also considered by Welcome. They have not been subject to complete qualification programme per API 5CT, but their reliability is proven by years of application. The connection selection depend on the material selection performed by corrosion analysis results. The selection criteria are showed here below grouped by material type. The listing order indicate the priority also. Material: Connection:

Incoloy 825, Duplex 1(25%, 22% Cr, Cold Worked), 28% Cr AMS 28 and VAM Ace

Material: Connection:

Martensitic 13% Cr. Hydril CS (o equivalent PJD8) AMS 28 VAM Ace


Low Alloy Steel

for offshore well

Hydril PH-6 (or equiv. PJD 6) Hydril CS (or equiv. PJD8) AMS 28 VAM Ace

for onshore well oil well, depth <5000 m:

AMS 28 Hydril CS (or equiv. PJD8) Hydril PH-6 (or equiv. PJD 6) VAM Ace

other cases:

Hydril PH-6 (or equiv. PJD 6) Hydril CS (or equiv. PJD8) AMS 28 VAM Ace


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22% e 25% Cr S.A. oil well:

AMS 28 VAM Ace Hydril CS (or equiv. PJD8) Hydril PH-6 (or equiv. PJD 6)

else:

Hydril CS (or equiv. PJD8) Hydril PH-6 (or equiv. PJD 6) AMS 28 VAM Ace

Carbon Steel

for offshore well oil well, depth <5000 m: else:

PJD Hydril PH-6 (or equiv. PJD 6)

for onshore well injection well (storage) :

AMS

production well:

3.9

3.9

depth <2500 m and SBHP <350 kg/cm²:

AMS

depth <2500 m and SBHP >350 kg/cm²:

PJD Hydril CS (or equiv. PJD8)

depth >2500 m and <5000 m:

PJD Hydril CS (or equiv. PJD8) Hydril PH-6 (o equiv. PJD6)

other cases:

Hydril PH-6 (o equiv. PJD 6)

WELL MONITORING

Injection rates, pressures and temperatures can be monitored continuously downhole using Downhole P & T instruments permanently installed in specific mandrels installed and connected permanently to the surface via an instrument wire (1/4” OD). This is done in a regular basis subsea injectors not being available any other means of having bottom hole measures or in installation where there is the need to continuously monitor Bottom Hole Flowing Pressure (e.g. ESP application). For land or platform applications common wireline techniques can be adopted; in particular in these wells it is sound to select downhole nipple profiles such to allow for the possibility of running PLT’s.


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3.10

WELL COMPLETION DESIGN EXAMPLE: WAKAR FIELD

3.10.1

INTRODUCTION AND TUBING STRESS ANALYSIS

Due to the location of the platform close to the shipping lines, to the well gas production and the rating required (7500 psi min), a special completion configuration has been designed, to guarantee for the well safety in case of accidental damage to the platform and/or to the wellheads. Besides the installation of a conventional Tubing Retrievable Safety Valve, infact, it has been foreseen the installation of a Sub Surface Tubing Hanger (Anchor). This, in case of accidental controlled rupture of the tubing above the Safety Valve, will hold the rest of the string intact and shut in the well at the Safety Valve. To allow for the controlled rupture of tubing above the Safety Valve, a pup joint manufactured with a ‘controlled section’ (machined for 80% of tubing yield for the two trips system) is installed below the mud line (almost 100 m from cellar deck). In case of an accident to the platform where this is taken off location, any bending of casings and pull on tubing will shear the ‘controlled section’ at the mud line living it undisturbed, ready for an overshot to catch it; the reaction point for the tubing while pulled is the tubing hanger positioned below the safety valve which for this purpose needs bidirectional slips. Two different configurations have been evaluated with different manufacturers: - One trip system; all downhole equipment run in a single stage. - Two trip system; two separate runs for lower and upper completions.

Table 2.5: Tubing Stress Analysis Result Summary: safety factor

Tubing size

3.5”, 9.2# 13 Cr

head

Max Prod. 1st year 2.82

Shut In 1st year 1.67

Injection 5000 psi 3 bpm 1.93

Pull 50,000 lb 1.54

SS Anchor

3.04

1.68

1.76

1.57

bottom

4.4 2.33

1.92 1.33

4.2 1.57

4.8 1.35

head

2.38

1.48

1.76

1.55 (*)

SS Anchor

2.63

1.49

1.64

1.63(*)

bottom

3.96 1.97

1.62 1.18

3.83 1.42

4.77(*) 1.25(*)

section

Safety Joint 3.5” 4.5”, 12.6# 13 Cr

Safety Joint 4.5” (*) 70000 lbs pull for 4½”


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Table 2.6: Anchor and Packer Loads Summary (1000 lbs - with direction é up and ê down)

Tubing size

3.5”, 9.2# 13%Cr

4.5”, 12.6# 13%Cr

Max Prod. 1st year

Shut In 1st year

Injection 5000 psi 3 bpm

Max Prod. 4th year

Min Prod. 10th year

Anchor 820 ft

17.2 ê

0.1 ê

28.0 ê

15.6 ê

4.7ê

Packer 11909 ft Anchor 820 ft

36.9 ê

54.2 é

63.7 é

59.3 ê

51.9 ê

18.2 ê

0.7 ê

35.7 ê

15.8 ê

0.5 ê

Packer 11909 ft

47.1 ê

88.7 é

96.6 é

82.7 ê

73.0 ê

section

Recommended configuration is for the two trips system, reasons for which are given in the integral study text.


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TUBING SIZE AND MATERIAL

The production profile requested will require to cope with a variety of rates and water cuts during the well life and bottom hole static pressure depleting quite rapidly. Moreover the high initial rate will require to maintain the ID as big as possible to accomplish for the erosional velocity of produced fluids. On this respect calculations have been done using a C factor of 200 not considering any sand/silt production. Conversely possible lifting of condensate drop out later in the field life would need to be accommodated through a ‘velocity string’ whose provision has been asked for. As a result, to comply with the initial rates and to guarantee for a safe production velocity through the Sub Surface Safety Valve and lowermost restrictions, a tubing 4 ½” 12.6 pounds per foot has been selected, considering all possible loads applicable during the well life (running, packer setting, production, killing). Material selected is Martensitic 13% Cr s.s., which will take care of possible corrosion resulting from condensation of connate water throughout the outflow and of possible produced water, due to the high content of CO2 . To accomplish for the installation of the 4 ½” it has been required the revisitation of the casing profile. The two wells have been suspended with the 9 5/8” as production casing, but, due to casing wear during drilling it has been required to tie back the 7” production liner at surface. This configuration does not accommodate for the installation of the 4 ½” 10K WP Sub Surface Safety Valve. For this reason the production casing profile has been reviewed; as a result the new profile foresees: 1. to cut and recover the present 9 5/8” @ 350 m below the mudline, 2. to tie back a mixed production casing (7” 29# at bottom swaged to 9 5/8” 47# at - 350 m anchored inside the drilling wellhead on the platform (cellar deck). This, besides guaranteeing the possibility to install the Safety Valve, will allow to install an integer production casing; moreover it will give a load shoulder for the system to suspend the string in accordance with proposals. Figure 2.13 shows one of the proposed completion sketch.


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Figure 2.13: Wakar field: one of the proposed completion sketch

well bay leve

sea level

safety joint

sea bed level

SCSSV 4.5" PJ

Sub Surface TBG HGR bi directional: allow annulus circulationand retrieval - rerunning

Packer Permanent - Retrivable

Perforated Joint


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FIGURES AND TABLES LIST

Figure 2.1: Inflow and outflow performance diagram Figure 2.2: Pressure gradient plot (production and injection) Figure 2.3: Prediction of minimum gas flow rate required for liquid removal (not to scale) Figure 2.4: Permissible expansion of a 1.0 gravity natural gas without hydrate formation Figure 2.5: Pressure (fig. 2.5A) & temperature (fig. 2.5B) gradient for production well Figure 2.6: Tubing size effect on the pressure gradient curves Figure 2.7: GLR effect on the pressure gradient curves Figure 2.8: Flow rate increasing effect on pressure gradient Figure 2.9: Gravity increasing effect on pressure gradient Figure 2.10: Oil viscosity effect on pressure gradient Figure 2.11: Tensile properties of Sumitomo 25%Cr 75 ksi steel Figure 2.12: Tensile properties of Sumitomo 13%Cr 95 ksi steel Figure 2.13: Wakar field: one of the proposed completion sketch. Table 2.1: Producible oil and gas rate range Vs tubing size Table 2.2: Pressure drop terms contribution Table 2.3: Applicability of pressure loss prediction methods Table 2.5: Tubing Stress Analysis Result Summary: safety factor Table 2.6: Anchor and Packer Loads Summary


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CHAPTER 4 - TUBING STRESS ANALYSIS DISTRIBUTION LIST TEAP STAP – Archive





€

Issued by

REVISIONS

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



PREP'D

CHK'D

APPR'D


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INDEX 4.1 TUBING STRESS ANALYSIS OVERVIEW ...............................................................................3 4.2 4.2 LOADING MECHANISMS....................................................................................................4 4.2.1 LOAD CASES FOR PRODUCTION & INJECTION WELLS.............................................5 4.2.2 PRODUCTION WELLS....................................................................................................5 4.2.3 INJECTION WELLS .........................................................................................................6 4.3 LENGTH VARIATIONS .............................................................................................................8 4.3.1 HOOKE’S LAW ................................................................................................................8 4.3.2 BUCKLING EFFECT ........................................................................................................9 4.3.3 BALLOONING EFFECT .................................................................................................14 4.3.4 TEMPERATURE EFFECT..............................................................................................15 4.4 TUBING-PACKER CONNECTION TYPES..............................................................................16 4.4.1 SLACK-OFF OR PICK-UP EFFECT...............................................................................17 4.4.2 PACKER SETTING ........................................................................................................17 4.5 TOTAL LENGTH CHANGE .....................................................................................................18 4.6 TUBING PACKER & PACKER CASING FORCES..................................................................19 4.6.1 TUBING TO CASING FORCE........................................................................................19 4.6.2 PACKER-TO-CASING FORCE ......................................................................................22 4.7 MORE ABOUT HELICAL BUCKLLNG....................................................................................22 4.7.1 THE SIGNIFICANCE OF BUCKLING.............................................................................23 4.8 STRESS, STRAIN AND DESIGN FACTORS DEFINITIONS ...................................................24 4.8.1 STRESS & STRAIN DEFINITION ..................................................................................24 4.8.2 AXIAL TENSION DESIGN FACTOR ..............................................................................26 4.8.3 BURST DESIGN FACTOR.............................................................................................26 4.8.4 COLLAPSE DESIGN FACTOR ......................................................................................27 4.8.5 RADIAL AND TANGENTIAL STRESSES ......................................................................27 4.9 TRIAXAL STRESS DESIGN FACTOR....................................................................................28 4.9.1 VON MISES EQUIVALENT STRESS INTENSLTY ........................................................28 4.9.2 EFFECT OF DIMENSIONAL TOLERANCES ON VME STRESS...................................29 4.9.3 TRIAXIAL LOAD CAPACITY DIAGRAM ........................................................................30 4.10 RECOMMENDED MINIMUM DESIGN FACTOR....................................................................31 4.11 FIGURES AND TABLES LIST ..............................................................................................33


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TUBING STRESS ANALYSIS OVERVIEW

Once available the tubing sizing result from Tubing performance design, that is when the pressure and temperature at wellhead and at bottom hole have been calculated for the well production and/or injection life, the stress analysis can start. The data required to perform the Stress Analysis study are: 1. 2. 3. 4. 5. 6. 7.

Well geometry (Measured and Vertical depth, deviation, dog-leg, casing size) Packer (setting method, size and Seal bore) Completion landing procedure Completion and Packer fluids density and general characteristics Production/Injection fluids characteristics (density, viscosity, temperature) Undisturbed well temperature Tubing properties - size, steel grade, coupling type, yield derating (CRA Corrosion Resistant Alloys), temperature derating and its anisotropy-.

The load cases are defined by means: 1. Annulus (tubing-production casing) Pressure behaviour at wellhead and bottom hole 2. Tubing Pressure behaviour at wellhead and bottom hole (due to production or injection) 3. Tubing temperature behaviour at wellhead and bottom hole (due to production or injection) Another tubing load can derived from: 4. Completion Landing procedure (considering also slack-off or pick-up) 5. Hydraulic Packer setting procedure (by tubing plug & tubing pressurising) 6. Completion Pullout 7. Tubing leak 8. Tubing evacuation 9. Tubing pressure test 10. Dual completion interaction The stress calculation is performed starting by Initial or Undisturbed condition in term of pressure and temperature and through the evaluation of the effect due to changing conditions. The effects on the tubular material can be summarised as following: Temperature increasing: string lengthening Temperature decreasing: string shortening Internal Pressure increasing: a) open tubing ballooning effect (string shortening) piston effect on the tubing bottom area (string shortening) b) plugged tubing ballooning effect (string shortening) piston effect on the plug (string lengthening) 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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External Pressure increasing: reverse ballooning (string lengthening) The previous superimposing effects on the string induce a length variation if the tubing string is free to move, otherwise if the tubing string is anchored an overall stress is induced on the string with the maximum values at packer section and/or at tubing hanger section. When the tubing length increase, caused by temperature and/or pressure effect, the first reaction of the steel is inelastic deformation, if the length variation is more than the maximum corresponding to the elasticity limit of the tubing string buckles and it assumes the characteristic helix shape. Some problem can arise by using long Wireline batteries in buckled string. The result of the tubing stress analysis are the evaluation of the Safety factors for any tubing string section for all exprected load cases. The definition of acceptable Safety factors has been standarised by AGIP in document STAP M1M-4002 dated 03.05.1995 “Tubing Design Manual” is herebelow summarized: Table 3.1: Required and acceptable safety factors

STEEL TYPE

CHARACTERISTICS

Carbon steel Corrosion Resistance Alloy C.R.A. 1 Corrosion Resistance Alloy C.R.A. 2

REQUIRED SAFETY FACTOR

MINIMUM ACCEPTABLE SAFETY FACTOR (only for particular condition)

1.25

1.15

Max 13% Cr, not cold worked

1.25

1.15

> 13% Cr and/or cold worked

1.35

1.20

Further the Safety factors evaluation concerning all tubing sections and all load cases singled out (located) the analysis should verify: 1. the tubing-packer reaction force, 2. the packer-casing reaction force 3. the packer resistance utilising the packer envelope supplied by manufacturers. 4.2

4.2

LOADING MECHANISMS

The tubing stress analysis performed in production or injection well completion assumes data as resulting from performance calculations: pressure and temperature gradients. The oil or gas production induces heating of the tubing and, decreasing radially, of the packer fluid and all the external casings.


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The continuous injection of water induces cooling of both the environment and the equipment: tubing, casing and reservoir, being the injected fluid always at a temperature reservoir’s one. When considering the tubing stress it is always required to start by considering the initial condition that occurs just before packer setting (if hydraulic) or tubing landing to correctly identify the kind of fluid present in the production annulus, in the tubing while setting the packer and the final packer fluid (mud, brine etc.). The stress in the tubing at the beginning of the injection is determined by the kind of fluid inside and outside the tubing string and by the packer setting pressure (if hydraulic) and setting procedure (i.e. depth of the setting plug, setting pressure etc.). The packer setting load case is the same both for production wells and for injection wells from the theoretical point of view. 4.2.1

LOAD CASES FOR PRODUCTION & INJECTION WELLS

4.2.2

PRODUCTION WELLS

The stresses induced in the string of Production wells completion can be summarised in four different load cases: 1. 2. 3. 4.

Completion landing and packer setting Start up (test and stimulation) Continuous production Completion pullout

The use of a modern simulator (Company Standard is ENERTECH Wellcat) helps in simplifying sensitivity simulations. The tubing packer connection can be selected: free to move, or fixed to the packer, that is latched or anchored. In case a free connection is selected, it is to consider that the connection seal packing will be negatively affected by a dynamic load due to thermal cycles. For this reason, it is recommended the use of moulded seal for packer seal units if many thermal cycles are foreseen due to frequent production shut-in. 4.2.2.1

COMPLETION LANDING AND PACKER SETTING

The completion landing stress have to be considered dependent on completion fluid because the tubing string weight depends on the buoyancy factor. The upper tubing string section is the most stressed section. The packer setting induced stress depends on the setting procedure. If the packer is hydraulic set type the setting plug area determines the stress on the string. There are two effects 1. pressure effect on the plug section (force = plug area x pressure at the plug depth)


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2. pressure ballooning effect (see paragraph on ballooning effect) 4.2.2.2

START-UP (TEST AND STIMULATION)

The heaviest stress induced on a production well tubing string is, generally, the stimulation operation ( Acid or Fracturing job). In fact in those case many cubic meter of acid and proppant at ambient temperature are injected at high rates into the well through the tubing. The effects are: 1. pressure effect on the bottom section of the tubing string (piston effect, Hook’s and Buckling effects) 2. pressure effect on the tubing string (ballooning effect) 3. thermal effect for tubing string cooling (string shortening or if fixed tubing packer connection force acting at the tubing packer interface) 4.2.2.3

CONTINUOUS PRODUCTION

The checks to perform are that the tubing string lengthening due to the temperature increasing does not determine an excessive buckling effect and a compression too heavy on the tubing packer connection. The buckling should be taken into account in terms of Wireline operability. 4.2.2.4

COMPLETION PULLOUT

The completion design should consider also the recovering of the string when the well will be abandoned. In some cases, when it is foreseen a string pulling to shear the device capable of releasing the packer, the pulling force is an extra load for the string. In this case, when using fluids with high solid contents, the possible solids deposition in the tubing production-casing annulus should be considered an extra pulling force shall be taken into account to be able to apply enough force on the shear pins at packer level. In these case the tubing string upper section is the most loaded section of the string. 4.2.3

INJECTION WELLS

The stresses induced in the string of Injection wells completion can be summarised in the following five different load cases, besides completion landing, packer setting and completion pullout shall require the same analysis done for the production well tubing. 1. Start up (test and stimulation) 2. Continuous injection 3. Re-start after shut-in 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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4. Completion pullout 5. Production Casing stress 4.2.3.1

START-UP

After the drilling and/or the casing perforation, often, the injection wells have to be tested to evaluate their Optimal Injection Rate (from which depends the required injection pressure). It is often convenient to stimulate the formation with an acid job to remove the damage induced by perforating and/or completion fluid or mud. In term of stresses this is probably the most severe load case for the completion in terms of pressure induced load, if the injection test and the stimulation are performed through the completion string. The injection pressure stresses the tubing with the “ballooning” effect (the differential pressure inflates the tubing) and with the “piston“ effect acting at the bottom of the tubing on cross section between min ID and seals OD. Both effects induce a length change: the first, being the tubing internal pressure greater than the external one, induces a tubing shortening; the second effect results in an upwards force applied to the bottom of the string which tend to reduce the tubing length. The relatively low temperature of the injected fluids (water and/or acid) will cool the environment down hole. The effect is, once again, a tubing length reduction. 4.2.3.2

CONTINUOUS INJECTION

The continuous injection induces the same loads as during start up, however the influence of the thermal load is greater than during start up due to the extended injection time. In selecting the well equipment it is a mandatory to take in due consideration that short time shut-in are always likely to occur during the life of an injection well; at any shut-in and the consequent re-start a thermal cycle is induced in both the equipment and the external environment. The thermal cycle determines a load cycle in the material and a consequent tubing length variation.

4.2.3.3

RE-START AFTER A SHUT-IN

When the injection is stopped for long time it is possible to have a deposition of bacteria growth that reduces, or even clog completely, the cross section flow area. In that case, when the injection re-starts, the injection pressure frequently should be increased to achieve the same rate before shut-in. Damage can in this case be removed by means of suitable chemical treatments.


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ANALYSIS OF TUBING STRESS

Once the load cases are properly defined, in terms of pressure and temperature, it has to be calculated the tubing length variation for every case, if the tubing packer connection is free to move, or the packer to tubing force if the connection is fixed (latched or anchored). In case a free connection is selected, it should be considered that the connection seal packing will be negatively affected by a dynamic movement due to thermal cycles. For this reason, it is recommended the use of moulded seal for downhole seal units in all water injection wells applications, even for anchored seal units, since also micromovements at seal element due to pressure reversals can damage the ‘V’ packing shape. 4.2.3.5

ANALYSIS OF CASING STRESS

The production casing, is loaded by the same thermal stress of the tubing; but the temperature variation is less important. If the casing is totally cemented and the cement has good quality, the casing does not change length. If the production casing is not cemented, or partially cemented, the sections without cement are subject to thermal stress. In this case the load at top and bottom ends should be considered and the section verified. In case of casing tie-back with hanger, in not cemented casing, also the hanger holding capability has to be verified. The last verification to be performed is the load on the casing upper section in case of tubing top section leak. In fact this is the worst load case for the production casing: the annulus is full of liquid (incompressible fluid), the injected fluid is water (incompressible) hence the injection pressure is transmitted instantaneously to the casing even if a relief valve is provided on the discharge line of the pump. 4.3

LENGTH VARIATIONS

Considering the tubing free to move it is possible to evaluate the string length variation for each one of the effects due to pressure, force and temperature changing. The sign convention is, as for all references in literature on the same argument, to consider: • compression force positive • string lengthening positive 4.3.1

HOOKE’S LAW

The elastic reaction of the string to the axial load due to buoyancy and to the pressure applied to the bottom section in a length changing as for the next formula (Hooke’s law):


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∆L 1 = −

9

(eq. 3.1)

where: F L E As

is the force active at the string bottom is the string total length is the elastic modulus of the steel grade used for tubing is the bottom string section (Seal bore Packer area minus tubing internal area) see Figure 3.1

Figure 3.1: Hooke’s law

∆L1

F

4.3.2

BUCKLING EFFECT

To define the string buckling the Neutral point concept should be introduced. Consider a string freely suspended in the absence of any fluid inside casing and an upward force F applied at the lower end of the string. The force compress the string and if it is large enough, the lower section of the string buckle into a helix. The compression is maximum on the lower section of the string and decreases the distance becoming zero at the Neutral point . The string above the Neutral point is in tension, starting from zero at the Neutral point and increasing upwards. The Neutral point is the place where the total primary axial stress is equal to the average of the radial and tangential stresses. Below the neutral point the pipe is buckled, whereas above this point the pipe is straight.


ARPO


IDENTIFICATION CODE

n w

10

OF

33


n=

PAG

F w

0 1

(eq. 3.2) is the distance between the neutral point and the bottom of the string (measured length) is the weight per unit length of the string considering the inside and outside fluids weight w = ws + wfi -wfo

(eq. 3.3)

wfi = Ai • γfi

(eq. 3.4)

wfo = Ao • γfo

(eq. 3.5)

Ai and Ao are the internal tbg area and the external tubing area γfi and γfo are the inside and outside fluids density To calculate the length variation due to buckling effect it is necessary to determine the Neutral point position. If the neutral point is located inside the string, in this case the string is partially compressed and partially tensioned and the tubing shortening can be evaluated be means of the following formula: ∆L2 = −

F2 ⋅ r2 8⋅ E ⋅ I ⋅w

(eq. 3.6)

if n < L

where: r I I=

is the tubing-casing clearance is the moment of inertia of tubing cross section with respect to its diameter, that is: π ⋅ (D 4 − d 4 ) 64

(eq. 3.7)

where: D is tubing OD d is tubing ID. w is the weight per unit length calculated the same way than in Hooke’s law formula


ARPO

IDENTIFICATION CODE


PAG

11

OF

33

REVISION 0 1

TEAP-P-1-R-8793

Figure 3.2: Buckling effect

∆L2

F

If the compression force applied to the string bottom is so high to buckle all the string, the Neutral point is located out of the string and the length variation can be evaluated by:

∆L2 = −

4.3.2.1

F2 ⋅ r 2  L ⋅ w  L ⋅ w  ⋅ ⋅2 −  8⋅ E ⋅ I ⋅ w  F  F  

(eq. 3.8)

if n > L

FORCE ACTING AT THE PACKER LEVEL: “PISTON” FORCE

The force to consider applied on the string to calculate the buckling effect is named Piston force and is calculated by the formula:

(

)

(

Fa = Pi ⋅ A p − A i − Po ⋅ A p − A o

)

(eq. 3.9)

The areas indicated in the formula can be found by figure 3.3.


ARPO

IDENTIFICATION CODE


PAG

12

OF

33


0 1

Figure 3.3: Areas for “piston” force calculation Ao Ai

r

Po

Pi

Ap

In the next three figures there are the possible tubing-packer connection in terms of areas. Figure 3.4: Areas for different tubing connection types

Ao

Ao

Ao

Ai

Ai

Ai

r

r

Po

Ap

Pi

r

Po

Ap

Pi

Po

Ap

Pi

Note that if the tubing outside pressure is greater than tubing inside pressure the buckling effect does not occur.


ARPO

IDENTIFICATION CODE


PAG

13

OF

33

REVISION 0 1

TEAP-P-1-R-8793

To summarise, the “piston” force “Fa” acts as per Hooke’s law if negative (tension) and both Hooke’s law and Buckling effect if positive (compression) 4.3.2.2

FORCE ACTING ALONG THE STRING: “FICTITIOUS” FORCE

The pressure acting along the tubing string is represented by the resultant applied at the bottom section. The actual forces are distributed along the whole string wall but for calculation purposes it is easy to apply the resultant: for this reason the force is called fictitious, not because it does not exist but only because it is the resultant of a distributed force. To understand the effects of the external and internal pressure on the string see the figure below: Figure 3.5: Internal and External pressure effects

R

Po

R

Po

Pi

Internal Pressure Effect

Pi

External Pressure Effect

The pressure effects can be calculated by Ff I = A i ⋅ Pi Ff II = − A o ⋅ Po

(eq. 3.10) (eq. 3.11)

where the first indicate the effects of the internal pressure along the lateral wall of the string equivalent to a force acting on the bottom section of the string as compression force. The second force indicate the effects of the external pressure on the external lateral wall of the string applied, as resultant, at the bottom of the string and acting as tension. 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


IDENTIFICATION CODE

PAG

14

OF

33


0 1

Note that the areas the forces are acting on, are different due to the both two forces, hence: Ff = Ff I + Ff II + Fa

(eq. 3.12)

The Fictitious force is defined, substituting the relations defined in the previous section, by: Ff = A p ⋅ ( Pi − Po )

(eq. 3.13)

The pressure to consider in the formulas of the fictitious force is the change in pressure inside the tubing at the packer level and the change in pressure outside the tubing at the packer level. The difference is intended from reference condition pressure and load condition pressure. The formula that defines the Fictitious force used to calculate the buckling effect becomes: Ff = Ap · (∆Pi - ∆Po)

4.3.3

(eq. 3.14)

BALLOONING EFFECT

The fluids flowing in the tubing give two effects: the pressure drop that modifies the radial pressure force, and a force on the tubing wall due to the drag force of the fluids. The Ballooning effect encompass both effects by the two terms of the formula: ∆L 3 = −

where: ν ∆Pim ∆Pom ∆ρi ∆ρo δ R L

2 ⋅ ν ∆Pim − R 2 ⋅ ∆Pom ⋅ ⋅ L - ν/L . [∆ρi - R² ∆ρo - δ . (1 + 2ν)/2ν].L² / (R²-1) E R2 − 1

(eq. 3.15)

Poisson’s ratio of the tubing material Change in surface tubing pressure Change in surface casing pressure Change of the density of liquid in the tubing Change of the density of liquid in the annulus Drop of pressure in the tubing due to flow per unit length Ratio OD/ID of the tubing Tubing length

δ is drop of pressure in the tubing due to flow per unit length as said and it is assumed to be constant. δ is positive when the flow is downward and conversely equal to zero in case of no flow. In figure 3.6 is showed the inside and outside pressure effect on the tubing.


ARPO

IDENTIFICATION CODE


PAG

15

OF

33

REVISION 0 1

TEAP-P-1-R-8793

Figure 3.6: Ballooning effect

REVERSE BALLOONING

4.3.4

BALLOONING

TEMPERATURE EFFECT

Often the temperature effect is the most important fraction of the total length variation. The effect is linked to the temperature variation and to the thermal expansion coefficient proper of the tubing material. The simple equation is: ∆L 4 = α ⋅ ∆TM ⋅ L

(eq. 3.16)

where: α

coefficient of thermal expansion of the tubing material (for steel α = 6.9 • 10-6 in/in/°F)

The average temperature variation can be calculated by: 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

IDENTIFICATION CODE


(T

final

− Tinitial

16

OF

33


∆TM =

PAG

)

Head

(

+ T final − Tinitial

)

bott om

2

0 1

(eq. 3.17)

Typical values of thermal expansion coefficient are listed in the table below: Table 3.2: Thermal expansion coefficient (α α) Carbon steel Low alloy steel 13%Cr (80-95 ksi) 22%Cr (65-110-120-140 ksi) 25%Cr (75-110-120-140 ksi) 28%Cr (110-125 ksi) Incoloy 825 (110-120 ksi) 4.4

6.9 • 10-6 in/in/°F 6.9 • 10-6 in/in/°F 6.1 • 10-6 in/in/°F 7.9 • 10-6 in/in/°F 6.89 • 10-6 in/in/°F 8.5 • 10-6 in/in/°F 7.92 • 10-6 in/in/°F

TUBING-PACKER CONNECTION TYPES

Tubing packer connection types considered for the stress analysis are showed herebelow:

Figure 3.7: Tubing-packer connections

FREE

FREE DOWN LOCKED

ANCHORED

The first, tubing free, allows all tubing movement, both downwards and upwards; this is the case of Polished Bore Receptacle (PBR) or Seal Bore Extension. The second allows only upwards movement and it is the same as above but with shoulder on the locator. The third, fixed tubing, does not allow any movement, it is the case of latched, anchored tubing, or tubing directly made up on the packer (modular setting).


ARPO


IDENTIFICATION CODE

17

OF

33


4.4.1

PAG

0 1

SLACK-OFF OR PICK-UP EFFECT

If the tubing packer connections are fixed type or Nogo down type it is possible to slack-off weight on the tubing string after packer setting. In this case the string is compressed. With fixed type connection it is possible to tension the string either pulling the tubing string or pressurizing it for setting an hydraulic packer. Figures below show the tubing packer connections: both allow to slack-off weight on the string, the second allow also to pick-up/tension the string. The weight slack-off is described by the formulas below, there are two terms: the first consider the elastic length variation (Hooke’s law) and the second the buckling effect.

∆L so

Fso ⋅ L Fso2 ⋅ r 2 =− − E ⋅ As 8 ⋅ E ⋅ I ⋅ w

(eq. 3.18)

where Fso is the slack off force on the packer. Figure 3.8: Tubing-packer connections for slack-off and pick-up

4.4.2

PACKER SETTING

To set an hydraulic packer, generally, the tubing pressure should be increased, at packer level, of a certain amount (generally in a range from 1500 to 4500 psi) after tubing has been plugged. Two effects act on the tubing string: the elastic reaction due to the pressure acting on the plug section and the ballooning effect.


ARPO


IDENTIFICATION CODE

PAG

18

OF

33


0 1

∆L1 = −

∆Fa ⋅ L E ⋅ As

(Hooke’s Law)

(eq. 3.19)

∆L 3 = −

2 ⋅ ν ∆Pim ⋅ ⋅L E R2 − 1

(Ballooning Effect)

(eq. 3.20)

where: ∆Fa = − A i ⋅ ∆Pi

(eq. 3.21)

∆Pim = ∆Pi

(eq. 3.22)

The scheme of the situation is shown in figure below. Figure 3.9: Packer setting

4.5

TOTAL LENGTH CHANGE

If the tubing is free to move, the total change is calculated by adding up the individual components and subtracting the possible length change due to slacking off: ∆LTOTAL = ∆L1 + ∆L2 + ∆L3 + ∆L4 - dLSO + ∆LPS

(eq. 3.23)


ARPO


IDENTIFICATION CODE

PAG

19

OF

33

REVISION 0 1

TEAP-P-1-R-8793

4.6

TUBING PACKER & PACKER CASING FORCES

4.6.1

TUBING TO CASING FORCE

When the tubing packer connection is fixed type or No-go down and it prevents the tubing movements (the No.go down just for downwards movement) a force acts on the connection and on the packer (as reaction). Prevented tubing shortening induces a force that it is possible to calculate using Hooke’s law: ∆L = −

F⋅L E ⋅ As

⇒

FP = − ∆L 4 ⋅

E ⋅ As L

(eq. 3.24)

It is the same to stretch the tubing of a lengthening ∆L4. Figure herebelow shows the situation and the diagram below shows the force-tubing length variation plot and the Fp and ∆L4 meaning. Generally the tubing packer reaction is a non linear problem due to the buckle of the string. In these cases the first step is to plot the system variation length/force diagram. That curve is plotted in figure 3.11, and length variation can be calculated by the following formulas:

∆L = −

F⋅L E ⋅ As

(for F < 0)

(eq. 3.25)

∆L = −

F⋅L F2 ⋅ r2 − E ⋅ As 8 ⋅ E ⋅ I ⋅ w

(for F > 0)

(eq. 3.26)

Then by the Fictitious force, previously calculated, the tubing situation load case can be located on the diagram. This point is (Ff, ∆Lf) on plot. Then an axis translation should be done to re-locate the origin in (Ff, ∆Lf); in fact a force as Ff applied to the string bottom, stretches the string and causes the buckling deformation. In the new axis’s diagram through the total length variation ∆Lp = - ∆Ltot it is possible to evaluate the string lengthening. That ∆Lp determines on the plot the tubing-packer force.


ARPO


IDENTIFICATION CODE

PAG

20

OF

33


0 1

Figure 3.10: Tubing-packer force

∆L4

Fp ∆L

∆L4

Fp

F


ARPO


IDENTIFICATION CODE

PAG

21

OF

33


0 1

Figure 3.11: Non-linear Tubing-packer force

∆Lp

Fp

∆L

Fp ∆Lp

∆Lf

F

Ff


ARPO


IDENTIFICATION CODE

PAG

OF

33

REVISION 0 1

TEAP-P-1-R-8793 4.6.2

22

PACKER-TO-CASING FORCE

The packer-to-casing force is simply the tubing-to-packer force plus the plug forces acting on the packer. It can be calculated as follow FP-C = FT-P + (AC - AP) ∆po

(eq. 3.27)

where: Ac = area defined by the casing ID, in2 ∆po = pressure differential across the packer, psi In some cases, eg fracture stimulation. although the tubing may have satisfactory design factors, problems may occur with the load rating of the packer. In these instances, the equipment manufacturer should be contacted and the anticipated packer loading discussed. 4.7

MORE ABOUT HELICAL BUCKLLNG

When a tube is loaded in axial compression, it will shorten in accordance with Hooke's law. However, if the tube is sufficiently long, which is almost always the case for well tubing, as the compressive force increases, a critical force will be reached that corresponds to an unstable condition. At this critical and higher compressive load, any amount of crookedness of the tube or slight movement of the load will cause the tube helically buckle. In presence of internal and external pressures, tubing behaves as if it was subjected to a force called the Fictitious or the effective buckling force. This force is given by: Ff = FTOTAL - (σt + σr) (Ao - Ai) = FTOTAL + (poAo - piAi) 2

(eq. 3.28)

The effective buckling force is sometimes also referred to as the excess axial force The criteria used for buckling is as follows: 1. - If Ff is negative, the tubing behaves as though it is in compression, and helical buckling, will occur. This concept can be difficult to understand since it is hard to visualise how the radial and tangential stresses affect buckling. 2. If the tubing is free to move and only subjected to pressure / area forces, the effective buckling force at packer depth reduced to Ff = Ao (po - pi)

(eq. 3.29)

Hence, in this situation buckling can only occur if the internal pressure is greater than the external pressure.


ARPO


IDENTIFICATION CODE

PAG

23

OF

33


0 1

Note, to maintain the correct sign for length changes (shortening is negative), use the absolute value of Ff in the buckling equations. 4.7.1

THE SIGNIFICANCE OF BUCKLING

Bending moments due to buckling or instantaneous dogleg generate axial stresses in the tubing. Bending induces axial compressive stresses in one side of the pipe and axial tension stresses in the other side of the pipe. The equation for the axial stress due to bending is as follows: σbend = + E x ID/2

∆θ/∆L 5730 x 12

(eq. 3.30)

where: ID/2 = pipe radius where the stress is calculated, in ∆θ/∆L = dogleg severity, deg/100 ft

In order to calculate the bending stresses due to buckling, the pitch, radius of curvature and dogleg severity should first be determined. The pitch is the distance in feet between spirals on the helix and is calculated with the following formula: P = π ( 8 E I )1/2 Ff

(eq. 3.31)

The radius of curvature of the helix in feet is given by: rc = P2 + 4 π2 r2 4 π2 r2

(eq. 3.32)

and equivalent dogleg in degrees per 100 ft: ∆θ/∆L =

5730 rc / 12

(eq. 3.33)

The dogleg calculated with the previous equation is plugged into the equation to determine the bending stresses due to buckling, σHB. These stresses are confined to the bends only, and hence they do not affect the axial force profile in the string. However, bending stresses may contribute to tubing failure by yielding the material, and they are therefore taken account of in the von Mises equivalent (VME) stress and, hence, in the triaxial design factor. Triaxial stress, or VME stress, will be discussed in a later section.


ARPO


IDENTIFICATION CODE

PAG

24

OF

33


0 1

Buckling of production tubing strings can be tolerated in many cases provided that the stress intensity in the pipe is at acceptable levels. Buckling is generally acceptable provided that the peak VME stress in the pipe, including the axial bending stresses due to buckling and deviation, are less than the specified minimum yield stress of the material with an appropriate design factor. Basically, there are two instances when buckling of production tubing is unacceptable even if the VME stress intensity is acceptably low: 1. When tools have to be run through the tubing, e.g. before and after perforating with a through-tubing perforating gun. 2. When the equivalent dogleg severity from buckling compromises the structural integrity or sealing capability of the tubing connections. Obviously, if the tubing is severely buckled, the running of tools in the tubing is complicated. Preferably, during conditions where it is necessary to run tools in the tubing, the tubing should not be buckled. However, it is generally possible to run tools in pipe which is only mildly buckled. The maximum free passage length for a tool in a helix shaped tube is calculated with the following formula: Ltool = P cos-1 [ (ID - ODtool) ] π ( r + ID / 2 )

(eq. 3.33)

where: Ltool = rigid length of a tool that can pass through the buckled tubing, ft ODtool = tool diameter, in ID = tubing ID or drift diameter, in -1 cos [...] cosine, in radians. The free passage length value can be used as a guide to determine if the amount of buckling will prevent the running of tools. Keep in mind that tools are not completely rigid and therefore the free passage length calculated is conservative. Remember, if buckling is a problem, it is possible to decrease the buckling intensity or eliminate buckling by applying external surface pressure which tends to straighten the pipe. Also, buckling can be lessened by using a lower initial slack-off weight if this is feasible. 4.8

STRESS, STRAIN AND DESIGN FACTORS DEFINITIONS

4.8.1

STRESS & STRAIN DEFINITION


ARPO


IDENTIFICATION CODE

PAG

25

OF

33


0 1

Stress is generated in a material when a force is applied; it is a distributed force inside the material. In the stress-strain diagram of steel are defined yield stress and tensile stress: the yield stress is the stress (in force per area unit) where beginning the plastic deformation of the steel out of the elastic region; The tensile stress is the maximum of the stress-strain curve, after that there is the rupture stress. When a tube is loaded in axial tension by a force, the axial stress can be evaluated by the following formula: F σ = _______ Ao -Ai where: σ is the stress in pound per square inches (psi) F is the axial force in pound Ao - Ai is cross sectional area in square inches The elongation or the deformation induced is the Strain: ε = ∆L / L where ε is the strain in pound per square inches ∆L is the change length in inches L is the tubing length in inches Elasticity of the ductile material is resumed by the modulus of elasticity or Young modulus, E, it is defined by Hooke’s law: σ=E.ε (E = 3.0 x 10^6 psi for carbon steel) The radial strain and the axial strain is linked, in the elastic region, by means of the Poisson’s ratio, that is: radial strain ν = -----------------axial strain (ν ν typical values is 0.3 for carbon steel)


ARPO


IDENTIFICATION CODE

PAG

26

OF

33

REVISION 0 1

TEAP-P-1-R-8793 σ tensile

ropture σ yield

Ε

ε

Figure 3.11bis : Carbon steel stress-strain diagram 4.8.2

AXIAL TENSION DESIGN FACTOR

Assuming that tubing connection which is equivalent to or stronger than pipe body is used, the axial tension design factor is calculated as follow: DFTENSION Yp 4.8.3

= Yp (Ao - Aj) / FTOTAL = Yield Pint

(eq. 3.34)

BURST DESIGN FACTOR

Barlow's equation for thin-walled pressure vessels is used to calculate the internal pressure resistance of the pipe body. The equation yields the pressure which generates a tangential stress in the pipe or coupling wall equal to the minimum specified yield stress of the material. Note, Barlow's formula is generally used for pressure vessels with a wall thickness that is approximately one-tenth or less of the vessel's radius. Barlow's formula assumes that the stress resulting from internal pressure is uniformly distributed across the wall thickness. If the wall thickness is greater than one-tenth the radius. Barlow's formula is conservative. The following formula is used to calculate the internal yield pressure for the pipe body: pb = 0.875 . 2 .Yp . t OD

(eq. 3.35)

where: t = wall thickness. in OD = external diameter of the tubing, in The 0.875 factor allows for the API minimum wall thickness tolerance. The burst design factor is given by: DFBURST= pb / (Pi -Po)

(eq. 3.36)


ARPO

IDENTIFICATION CODE


PAG

27

OF

33


0 1

pb = Minimum Internal Yield Pressure (Pi - Po) = Differential Burst Pressure 4.8.4

COLLAPSE DESIGN FACTOR

4.8.4.1

COLLAPSE MODE

There are four possible API collapse failure modes: • Yield strength collapse • Plastic collapse • Transition collapse • Elastic collapse The appropriate collapse mode is determined by comparing the ratio of the tubing's OD/t with the calculated values of OD/t which indicate the transition between the modes. Unfortunately, the values of OD/t vary with axial stress, and so have to be calculated at each point in the tubing where there is a change in loading. The step by step procedure below based on API Bulletin 5C3 details the process and is repeated at each section of the string where there is a change in loading. 1. 2. 3. 4. 5.

Determine reduced Yield strength Ypr Determine OD/thickness ratio at the transition between collapse mode Compare actual OD/ thickness with the transition ratio (previous step) Determine appropriate collapse pressure Determine collapse design factor

4.8.4.2

COLLAPSE DESIGN FACTOR DETERMINATION

The collapse design factor is given by: DFCOLLAPSE =

4.8.5

pc (po - pi)

=

CollapsePressureResistance Differential Collapse Pressure

(eq. 3.37)

RADIAL AND TANGENTIAL STRESSES

The inner and outer radial and tangential stresses are calculated from Lame’s equations for thick walled cylinders. The radial stress is given by: σr

= pi Ai - po Ao _ (p i - p o) Ai Ao (Ao - Ai) (Ao - Ai) A

(eq. 3.38)


ARPO


IDENTIFICATION CODE

PAG

28

OF

33

REVISION 0 1

TEAP-P-1-R-8793

where: =area corresponding to either inner or outer radius, in2

A

For the inner radius (A = A i ) this reduces to: σr,j = -Pi and for the outer radius (A = Ao): σ r,o = -po The tangential stress is given by: σt

= pi Ai - po Ao _ (p i - p o) Ai Ao (Ao - Ai) (Ao - Ai) A

(eq. 3.39)

For the inner radius this reduces to: σ t,j = pi (Ai + Ao) -2 po Ao (Ao - Ai)

(eq. 3.40)

and for the outer radius: σ t,o =

4.9

2pi Ai - po (Ai + Ao) (Ao - Ai)

(eq. 3.41)

TRIAXAL STRESS DESIGN FACTOR

Axial force and pressure loads generate triaxial stresses in tubing rather than biaxial or uniaxial stresses as inferred by the API load capacity equations. The three principal stresses for a cylinder or tube are axial, radial and tangential. 4.9.1

VON MISES EQUIVALENT STRESS INTENSLTY

An accurate and widely accepted criterion for predicting the onset of yielding of ductile, isotropic materials is the distortion-energy theory. This theory is also called the shearenergy theory or the Hencky-von Mises theory. The Hencky-von Mises theory is based on energy concepts. The total elastic energy is divided in two parts: one associate with the volumetric changes of the material and the other causing shearing distortions. A yield criterion for combined stress is established by equating the shearing distortion energy at the yield point in pure tension to that under combined stress. Well documented experiments have shown that the Henckv-von Mises theory predicts yielding of ductile isotropic materials with a high degree of accuracy. The mathematical statement of this theory for a cylinder is given below. The VME stress, is calculated as follows:


ARPO


IDENTIFICATION CODE

PAG

29

OF

33


σVME ={0.5 (σa - σt )2 +(σt - σr)2 +(σr - σa)2}^0.5

0 1

(eq. 3.42)

The triaxial stress intensity design factor is given by: DFVME =

YP σVME

=

Minimum Specified Yield Stress VME Stress

(eq. 3.43)

In the absence of bending, the peak VME stress always occurs at the pipe inside surface. If bending due to buckling or instantaneous doglegs occurs, the peak VME stress can occur on the pipe inside or outside surface. As stated previously, bending generates axial compressive stresses in one side of the pipe and axial tensile stresses in the other side of the pipe. The procedure to calculate the peak VME stress in tubing subjected to bending moments is as follows: 1) Calculate the radial and tangential stresses on the pipe ID and OD using Lame's equations 2) Calculate the bending stresses due to helical buckling and hole deviation on the pipe ID and OD 3) Calculate the maximum axial stresses on the pipe ID and OD 4) Calculate the VME stress at the four locations The peak VME stress is the maximum of the four calculated above. Direct comparison of the peak VME stress to the yield stress of the material provides a single equivalent design factor for all the simultaneous loads imposed on the string. 4.9.2

EFFECT OF DIMENSIONAL TOLERANCES ON VME STRESS

Since tubing is manufactured with dimensional tolerances on the pipe OD and wall thickness these tolerances should be considered when calculating the VME stress intensity. The API tolerances for tubing are shown below. The higher VME stresses are calculated for pipe with minimum allowable wall thickness and maximum allowable OD. Hence, to calculate the maximum possible VME stress, use the maximum OD, minimum wall thickness and corresponding radii to calculate the axial, bending and tangential stresses.


ARPO


IDENTIFICATION CODE

PAG

30

OF

33


0 1

Table 3.3: API dimensional tolerances for tubing _______________________________________________________________ Tolerance Outside diameter, OD: 4.0” and smaller +/-0.03” 4.5” and larger

Wall thickness, t

+1.00% -0.50% -12.50%

Weight: Single lengths Car-load lots

+6.50% -3.50% Car-load lots -1.75% _______________________________________________________________ A car-load is considered to be a minimum of 40,000 LB (18,144 kg). Inside diameter. ID is governed by the outside diameter and wall thickness. 4.9.3

TRIAXIAL LOAD CAPACITY DIAGRAM

A method has been developed to represent the triaxial load capacity of the pipe on a twodimensional graph. The triaxial load capacity diagram is a representation of the VME triaxial stress intensity in relation to axial force and either internal or external pressure. Since the triaxial stress is defined by these three independent variables, a normalization procedure is used to create a two-dimensional representation. The normalization operation used to create the diagram shows the planes where external pressure equals O psi as the top half or burst region of the figure. The plane where internal pressure is O psi corresponds to the lower half or collapse region of the diagram. The anticipated service loads along the length of the string can be plotted on the triaxial load capacity diagrams. For different burst pressure loads, the normalized internal pressure generating the same triaxial stress with the same axial force as the combined load, but at O psi external pressure, is calculated and plotted on the diagram. An analogous procedure is used to obtain a normalized external pressure under differential collapse pressure loading. Additionally, the specified API load capacity design factors for pressure (burst and collapse) and axial tension can be graphically represented. A direct visual comparison can be made between the anticipated service loads and the API load capacity and VME stress intensity design factors. An example of a triaxial load capacity diagram is shown as Figure 3.12. The following parameters are useful in understanding the diagram:


ARPO


IDENTIFICATION CODE

PAG

31

OF

33


0 1

1. The API operating window is the area enclosed by the API pressure and tension capacity of the pipe, adjusted by suitable design factors. The biaxial effect of tension on collapse resistance is included. 2. The Von Mises stress curve defines the stress level in the pipe in terms of internal or external pressure and axial force. The inner dashed curve shows the application of a design factor to the peak VME stress. 3. A service load line shows the variation in the stress intensity in a tubing string over the length of the string. 4.10

RECOMMENDED MINIMUM DESIGN FACTOR

The term safety factor is often misused for design factor. A design factor is the rated load capacity of the member divided by the maximum anticipated load on the member. A safety factor on the other hand is the failure load of the member divided by the actual load on the member. Obviously, prudent engineering practices require that the actual safety factor be larger than the design factor. The following minimum acceptable design factors are recommended to ensure a safe tubing string design: • API load capacity burst pressure 1.3 • API load capacity collapse pressure 1.1 • API load capacity axial tension 1.6 • Load capacity axial compression 1.2 • VME stress intensity 1.25 (Carbon steel) • VME stress intensity 1.33 (C.R.A.) The minimum acceptable design factors listed above should be viewed as guidelines rather than absolute cut-offs. Of course, use of a tubing string design with lower than recommended design factors should be approved by management. In these instances, the consequences of running a tubing string with lower than recommended design factors have to be thoroughly evaluated. Note, the added cost to upgrade a tubing string to a stronger design is inconsequential as compared to the cost of a workover or catastrophic failure. As stated previously, design factors for tubular products are based largely on past experience. Nevertheless, some justification for the minimum recommended design factors listed above can be offered. Since it is essential that it is possible to recover the tubing from a well, a relatively high axial tension design factor is justified. A minimum axial tension design factor of 1.6 based on yield stress should be maintained for all anticipated service conditions. Use of a minimum axial tension design factor of 1.6 also provides additional overpull capability in case the tubing becomes stuck and subsequently have to be pulled from the well. When this happens, it is common practice to apply overpull forces up to the pipe or connection yield strength, ie an axial tension design factor of 1.0.


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Many operators use a minimum acceptable burst pressure design factor as low as 1.0. Note that a burst design factor of 1.0 results in an automatic 10% under-design. Even if the pipe were hydrostatically tested to the API maximum alternate test pressure, at a l.0 burst design factor the pipe could be subject to an in-service pressure higher than the test pressure. Prudent engineering practices dictate that the pipe should never be exposed to an in-service pressure higher than the test pressure. Since the minimum internal yield pressure is based on 87.5% of normal wall thickness and the hydrostatic test pressure is equivalent to 80% of nominal pipe, a 1.094 internal pressure design factor is required to prevent working the pipe to a pressure higher than the test pressure. For some sizes, weights and grades where the coupling partially controls performance properties, the maximum alternative API hydrostatic test pressure is 80% of the internal pressure resistance rating. Consequently, as a practical minimum, a burst design factor of 1.25 is required. Moreover, 1.30 is preferable and is used by many operators. A relatively low API load capacity collapse pressure design factor is conventionally used for two reasons: 1. The probability of the well being completely evacuated is lower than the probability of the axial tension and differential burst pressure loads that are normally considered. 2. Although collapse failures are unacceptable they generally do not result in an extremely dangerous situation. A burst failure or rupture can lead to a blow out and lives can be lost if such a failure occurs. Since the VME design factor which considers all the significant variables affecting the pipe is a very accurate indicator of the relative safety of the string design, a relatively low VME design factor is acceptable. The primary justification for all of the recommended minimum design factors is experience. Experience with all types of oil and gas wells has shown that use of the recommended design factors combined with a realistic analysis method and good engineering practices result in safe tubing string designs. Furthermore, none of the recommended minimum design factors can be considered excessive. Consequently, use of these design factors should not lead to excessively costly or over-designed tubing string designs.


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FIGURES AND TABLES LIST

Figure 3.1: Hooke’s law Figure 3.2: Buckling effect Figure 3.3: Areas for “piston” force calculation Figure 3.4: Areas for different tubing connection types Figure 3.5: Internal and External pressure effects Figure 3.6: Ballooning effect Figure 3.7: Tubing-packer connections Figure 3.8: Tubing-packer connections for slack-off and pick-up Figure 3.9: Packer setting Figure 3.10: Tubing-packer force Figure 3.11: Non-linear Tubing-packer force Figure 3.11bis : Carbon steel stress-strian diagram Figure 3.12: Triaxial load capacity diagram example

Table 3.1: Required and acceptable safety factors Table 3.2: Thermal expansion coefficient Table 3.3: API dimensional tolerances for tubing


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Volume 1 CHAPTER 5 - PACKERS -






€

Issued by

REVISIONS

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



PREP'D

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APPR'D


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INDEX 5. PACKERS.......................................................................................................................................3 5.1 GENERAL .................................................................................................................................3 5.2 PACKER TYPES.......................................................................................................................4 5.2.1 SINGLE PACKER ............................................................................................................4 5.2.2 DUAL PACKER................................................................................................................4 5.2.3 ESP PACKER ..................................................................................................................4 5.3 PACKER SETTING MECHANISM.............................................................................................5 5.3.1 MECHANICAL SET..........................................................................................................5 5.3.2 HYDRAULIC SET.............................................................................................................5 5.3.3 HYDROSTATIC SET........................................................................................................5 5.4 PACKER SELECTION CRITERIA.............................................................................................6 5.4.1 SINGLE PACKER SELECTION CRITERIA......................................................................6 5.4.2 SINGLE PACKER ..........................................................................................................10 5.4.3 PACKER SETTING METHOD SELECTION...................................................................12 5.4.4 TUBING PACKER CONNECTION .................................................................................14 5.4.5 TUBING-PACKER CONNECTION .................................................................................19 5.5 SINGLE SELECTIVE COMPLETION PACKER ......................................................................20 5.5.1 PACKER TYPE SELECTION .........................................................................................20 5.5.2 PACKER SETTING METHOD SELECTION...................................................................22 5.5.3 TUBING-PACKER CONNECTION SELECTION ............................................................22


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GENERAL

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Packer, together with tubing, safety valve and wellhead constitutes the basic elements a completion shall include to be considered safe; infact packerless completion can not be considered ‘intrinsically safe’, since their effectiveness is linked to the capability of the completion fluid to maintain the stability of its rheological characteristics, which can not be guaranteed for long period of times, and to the absence of corrosive fluids. Packer function is infact to isolate the produced fluids from the packer fluid guarantying this with its rating, which is the maximum differential pressure it can withstand from top down or from bottom up, during all production/injection conditions. Generally speaking the packer, whatever the type and the application, has some basic components which will be present in different shapes and locations but with same basic function: - packer mandrel: this is the body of the packer itself where the fluid will flow; in single packers is generally solid while it can be spliced in multiple string packer, - packing element: this is the rubber element which is compressed during the setting sequence and stores the setting energy, hydraulically separating fluids above and below it, sealing on the mandrel and on the casing ID, - cones and slips: they are the mechanic elements that, run in relaxed position, when activated, reciprocates; the slips bite and engage the casing ID supplying the reaction point for the complete packer setting movement and for the rubber compression. Their shape should be designed to optimise the gripping action as a function of the packer rating avoiding to cause a permanent casing damage, especially in unsupported (not cemented) casings, - ratchet system: this, done in different shapes and positioned in different locations inside the packer, is usually composed of two cylinders (the external one cut longitudinally) which mates through a series of opposing triangular teeth provided with one iclined flank and one vertical flank; during packer setting movement the two cylinders reciprocally moves sliding on the iclined flanks and the external cylinder elastically deforms to jump one tooth at a time; the reverse movement is not allowed by the combined action of the vertical flanks and store in practical the mechanical energy used for the packer setting.


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PACKER TYPES

According to the general definition it is clear that packer characteristics and configurations depend on the different applications they should be applied to. Main subdivision can be done on number of tubings should be connected to it, then on packer setting/retrieving methods.

5.2.1

SINGLE PACKER

5.2.1.1

RETAINER/PERMANENT

It is a packer that allows the passage of only one flow path and, once set, can not be retrieved or removed either that by milling its external components down to the slips and cones. In selective completions it is usually used as bottom packer. It can be single bore or dual bore with respect to its ID to accommodate different type of tubing/packer connections as function of min ID required. 5.2.1.2

RETRIEVABLE

It is a packer which, after setting, can be retrieved, and in the general nomenclature, by this definition it is intended retrieved by straight pull on the production tubing itself; the retrievability is achieved through the shear of a device which allows generally the packer to relax downward, releasing the energy stored by its ratchet and packing system. 5.2.1.3

PERMANENT-RETRIEVABLE

By this definition it is intended a packer which acts during setting and normal operations like a retainer packer, and, when pulling of the completion is necessary, can be retrieved without milling. To accomplish this, usually two separate operations are required: first it is required to pull out the tubing string; then with a work string and a special retrieving tools a second run is required to activate the device which relaxes the packer downward. Lately are available on the market packers of this kind where the releasing device is activated either by wireline or hydraulically. 5.2.2

DUAL PACKER

This kind of packer is always retrievable and has two bores through it; it is always hydraulic/hydrostatic set and exist in two versions; with or without scoop head. With scoop head means that the packer is run on a single string and the second one is landed on a second run; clearly this type can be use only as a top packer in a multiple installation where no safety vales are installed, since geometrical interference of tubing retrievable safety valves at the top of the well will impair the run of the two strings separately. Without scoop head means that the two strings are run simultaneously using dual elevators, slips and BOP rams at surface.

5.2.3

ESP PACKER


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Derived from dual bore packers they are nowdays available in multibore version, hydraulic set and retrievable; clearly not very high rating packers, they make available several bores for: - main flow passage - ESP power cable passage - Gas venting separate passage - chemical control line passage - electrical P&T instrument cable passage Late version of these packers usually foresee all the above mentioned bores obtained machining a solid block which is provided externally with the setting/releasing mechanism

5.3

PACKER SETTING MECHANISM

5.3.1

MECHANICAL SET

This type of setting can be tension or compression set, usually coupled with some sort of rotation at the packer to disengage the setting mechanism by friction of centralizers against the casing wall; main application of compression set mechanical packer is packer used for well testing. Other type of mechanical set packers is the complete suite of retainer packers which can be set either wireline or with its hydraulic setting tool. They incorporates only the packer basic elements, the setting mechanism being incorporated in their setting tool. They are used as foot packer in a multiple retrievable selective completion, as pump packer in gravel pack or as multiple stacked packer in single selective completion where pulling the string is not foreseen. 5.3.2

HYDRAULIC SET

This kind of packers usually are more costly than the mechanical set due to the more complex machining and manufacturing required. For the setting sequence they need usually that the tubing below is plugged and tubing pressured up, to initiate the sequence. Normally at a limited pressure, first set of shear pins (retaining cone and slips) shears, allowing their movement to engage the casing wall so fixing the reaction point for the complete setting. 5.3.3

HYDROSTATIC SET

Few packers of this type are available on the market in single or dual retrievable configuration. The main feature is the fact that the setting mechanism is activated at very low tubing pressure, since this pressure only frees the movement of a piston which is sucked by the action of the atmospheric pressure trapped in a chamber at surface. For this feature they are preferentially applied in shallow set retrievable completions or when the Xmas tree is not rated high enough to accomodate for packer setting pressures.


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PACKER SELECTION CRITERIA

5.4.1

SINGLE PACKER SELECTION CRITERIA

5.4.1.1

INTRODUCTION

Scope of this chapter is the definition of AGIP criteria for packer selection to be employed in single or single selective wells. They reflect in house expertise and most recent installation case history. Packers considered in this document are specified in Table 1. Proposed selection criteria are limited to the definition of technical aspects which justify the selection; they do not reflect specific characteristics of ‘brand’ models even if at the end they will drive to the selection of more common models available. The criteria relevant to metallic material recommendation are specified in Chapter 1 while elastomeric material selection criteria are under writing and will be presented later. Once defined packer type, size and model, the tool shall be structurally verified in all its production envelope (applied forces and pressure differential reversals). In this respect, Figure 1 shows a typical packer envelope curve; these curves are normally available for retainer packers while are available for packer retainer-retrievable in only few cases; for retrievable packers only the pressure rating is normally available It is a good engineering practice to always ask for these curves, to force suppliers to provide them. It has sometimes occurred that a supplier, forced to provide the curve, has modified the packer deign to satisfy the originally declared pressure ratings. Table 1. Packer

Setting

Setting Tool

Sealbore

Retainer

Mechanic

Hydraulic Setting Tool Electric Line

Hydraulic

Std/Large/Dual Std/Large/Dual Std/Dual

Mechanic Hydraulic

Std/Large/Dual Std/Dual

Permanent Retrievable

Retrievable

Hydraulic Hydrostatic Set down weight

Figure 1.


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40000 Rc=30-32

30000 20000 10000 Force (lbs)

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Nace Rc<=22

5.4.1.2

20000

Pressure (psi)

10000

0

-20000

-20000

-10000

-10000

GENERAL SELECTION SCHEME

Definition of packer selection characteristics has been divided as follows: 1. 2. 3.

Packer type Setting methodology Tubing packer connection

Whenever the stress analysis, done as per Chapter 3 criteria, would fail at packer-tubing connection level, the original tubing-packer connection selection shall be modified to accomodate all the foreseen operations (stimulation, killing, production). 5.4.1.3

CRITERIA DESCRIPTION

Method described will make extensive use of flow charts to illustrate and possibly standardise specific steps. The algorithm ‘If-Then-Else’ has been extensively used either as a main criteria or as exception to more general rules. For the full evaluation to be possible following data shall be available: 1. 2. 3.

Well data Completion data Operation characteristics

Well data generally describe the well configuration: • • • • •

Well position (on-shore/platform, off-shore) Pressure and temperature Well type (production, injection) Type of produced fluids (oil, gas) Well max deviation.

Completion data include all informations already available when selecting the packer: •

Completion fluid type and specific gravity


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Method for casing perforating (tubing-conveyed or wireline) Presence of a production liner.

Some of the data of this set are looped in this module itself (i.e: to decide for the setting sequence it is necessary to know the packer type and setting depth). Concerning operations following types have to be considered: • •

5.4.1.4

Stimulations (yes,no) Completion pull out operations like: - only tubing pull out, or tubing & packer pull out - pull out frequency - possible damage induced by the workover fluid.

METHOD RESULTS

Figure 2 shows the iterative process to refine the complete packer-tubing connection selection; while going on the different attributes which will be defined are: • •

Packer Type: Retainer, Permanent-Retrievable, Retrievable Setting Method: - Packer Retainer and Permanent Retrievable: Hydraulic, Mechanical (By Workstring, By Wireline) - Packer Retrievable: Hydraulic/Hydrostatic, SetWeightDown

•

Seal Assembly Type for Retainer packer or Permanent/Retrievable: Anchor, Anchor with ShearRelease, Standard (short) Locator, Anchor with PBR (Polished Bore Receptacle), LongLocator with SealBoreExtension.


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Start

Packer Type

Setting Mechanism

Tubing - Packer Connection Type

Stress Analysis

No

Stress Analysis O.K.?

Yes

Final Configuration

Figure 2. Packer-Tubing connection selection

It is not always possible to define a one only solution during the process; frequently, infact, the different initial approach can drive to different solutions. In these case the engineer has the possibility to choose among a series of different accepted solutions.

5.4.1.5

WELLS CLASSIFICATION

An important parameter for the packer characterisation is the well criticality. At this regard, four different class of wells have been identified which require different approaches in packer selection: • •

Highly corrosive well Extreme well (one or more of following conditions apply): - extreme depth (> 4500 m.) - high temperature (SBHT > 130 °C) - high pressure (SBHP > 700 atm.) - subsea well - platform well (risk due to a possible impact on the jacket of a vessel) - gas injection wells: (Injection Tubing Head Pressure - ITHP) greater than 3000 psi.


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Difficult well - temperature between 100 °C and 130 °C - depth between 3000 e 4500 m.

•

Normal well - temperature below 100 °C - depth to 3000 m.

Indicated depth shall be intended vertical.

5.4.2

SINGLE PACKER

5.4.2.1

PACKER TYPE SELECTION

In this case the selection is driven towards different choices depending mainly on the well type classification: 1. In an ‘extreme well’ : select a Retainer packer. 2. In a ‘highly corrosive well’: select a Permanent Retrievable or Retainer packer, first one being the priority selection 3. In a ‘difficult’ or ‘normal well’: select a Retrievable or a Permanent Retrievable packer, first one being the priority selection Rectangle "Select" show the possibility for the engineer to select between two alternatives; selection priority is indicated by a number ("1" has priority on "2"). As an example in the selection consequent to test (D), packer does not require special retrieving conditions (no foreseen workovers, no special packer fluids demands); safe selection of a Retrievable packer is function of well criticality, in particular to its depth.


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REVISION 0 1

TEAP-P-1-R-8794

Figure 3 Key tests are: (A) Tubing pullout foreseen high frequency (completion life < 5 years).

Start

Yes

PAG

(B) Tubing-packer pullout foreseen high frequency (completion life < 5 years). (C) TCP perforation technique used. (D) Measured well depth > 3000 m. (E) W.O. fluid is supposed to be damaging. (F) Packer fluid is a high specific gravity fluid (> 1.6 kg/l) with possibility of solids settling. (G) Well is gas injector with ITHP > 3000 psi.

(A) No

No

Yes (G)

Yes

No (B)

Yes

Yes (C)

(C)

No

No

Yes

No (E)

(F) Yes

No No (F) Yes

No (D) (1)

Yes

(2)

Choice (2) Choice (1)

Retainer

Retrievable

Permanent Retrievable

Figure 3. Packer type selection


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5.4.3

PACKER SETTING METHOD SELECTION

5.4.3.1

RETAINER AND PERMANENT RETRIEVABLE PACKER

Also in this case well criticality drives the selection: 1. 2.

If well is ‘corrosive’ or ‘extreme’ select the hydraulic setting. If well is ‘difficult’ or ‘normal’.

Start

1

Choice 2

Yes

0

No

(A)

Hydraulic

Mechanical By Workstring

Mechanical By Wireline

Figure 4. Retainer Packer Setting Method Selection

Figure 4. key tests description. Test (A) is true if one of following conditions apply: • • • •

SBHT > 150 °C Well max deviation > 50° Packer fluid specific gravity > 1.6 kg/l Production liner inclination > 30°

The Retainer Mechanic packer setting method is defined by test (A) Figure 4; same procedure apply for a similar packer used in a selective completion.


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TEAP-P-1-R-8794 5.4.3.2

13

RETRIEVABLE PACKER

This packer type setting method selection follows Figure 5 flow chart. Start

No (E)

No

No (F)

Yes

(A) Yes

Yes (B) Yes No (C) Yes No

Permanent Retrievable packer

Mechanical Setting

Mechanical Setting

Figure 5. Retrievable Packer Setting Method Selection Figure 5. Key tests description Test (A) is true if one of following conditions apply: • • • •

SBHT > 60 °C Well max deviation > 20° Packer depth > 2000 m (referred to permanent-non test installations) Stimulations are foreseen

Test (B) Test (C) Test (E) Test (F)

TCP perforation technique used. Tubing pullout foreseen high frequency (completion life < 5 years). W.O. fluid is supposed to be damaging. Packer fluid is a high specific gravity fluid (> 1.6 kg/l) with possibility of solids settling.

The engineer has to decide by himself about the need to select an hydrostatic packer instead of an hydraulic one; major difference being the overall setting pressure (lower for the hydrostatic) which will impact on the Xmas Tree Rating.


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The presence of particular conditions at packer setting can induce to shift from the selection of a Retrievable packer. In this case the recommended choice is in favour of a Permanent Retrievable one; as a consequence the relevant setting method shall be applied (see 1.3.3). 5.4.4

TUBING PACKER CONNECTION

5.4.4.1

RETAINER & PERMANENT RETRIEVABLE PACKER

This chapter examines basically two steps: • •

Drive the engineer to select the packer-tubing connection Tailor the selection done to tubing stress analysis results

In packer-tubing connections all sealing elements shall be foreseen as molded seals whenever subject to cyclical pressure reversals (i.e. gas injection wells where IBHP> packer fluid gradient pressure and SBHP < packer fluid gradient pressure). ‘Extreme Well’; Anchored Completions In an ‘extreme’ well (see 1.2.3), the first approach is to select an anchored packer-tubing connection' Figure 6 test. With reference to Figure 7 packer-tubing connection is defined by test (A); in particular the choice is between a shear release or an anchor seal assembly. As a further refinement of this choice, anchor can be specified even more: • •

If the packer is mechanically set, the anchor will be ‘Snap Latch’ type; otherwise ‘Solid Latch’ type. If the tubing stress analysis is negative: - using a Shear Release Anchor: pass to a Solid Latch Anchor - using a Solid Latch Anchor: pass to a Moving Seal Assembly (see Figure 7).


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Start

yes

Anchor with Shear Release

(A)

no

Anchor solid latch

Figure 6. Extreme Well - Anchored Completion ‘Extreme Wells’; Moving Seal Assembly This module should be entered if an Anchored completion does not satisfy the stress analysis at the tubing packer connection. A Moving Seal Assembly is the next step. (Figure 7).


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TEAP-P-1-R-8794

Anchored Completion Stress Analysis failed

Well Bore Type

Standard

Large

Dual

Yes No

(A)

(A)

No

Yes (B)

No

No

(B) Yes

Seal Bore = Standard

Anchor With PBR

Seal Bore = Large

Long Locator With Seal Bore Extension

Seal Bore = Dual

Anchor With PBR

Figure 7. Second option of the first case: Floating seal

Figure 7. Key test description Test (A) Test (B)

Packer fluid is a high specific gravity fluid (> 1.6 kg/l) with possibility of solids settling. "One trip" completion. Valid only for hydraulic set packer.

Figure 7 shows the criteria to adopt for selecting the moving seal assembly; it will be referred later for other different cases. In this case, whenever the stress analysis would still fail, there is no space for further modifications since any correction action to be taken will not deal with the tubing-packer connection.

‘Difficult , Normal’ Wells Simplest approach is to select a Standard Locator (case 1).


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TEAP-P-1-R-8794

Type and setting mechanism of selected packers

Yes

No

(A)

(B)

Yes

Yes

No

Yes

(C)

(C)

No

(D) (D)

Yes

No

Yes

(D) Yes

No

No No Anchor

Hydraulic Packer Shear Release

Stress Analysis

Stress Analysis

Locator

Failure

Failure Anchor with PBR Figure 8. Sealing Element for 'Difficult' - 'Normal' wells (2nd case). Mechanical packer standard locator

This occurs if following conditions apply simultaneously: 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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• • •

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no stimulations are foreseen well is not an injector packer is not hydraulic set

When above conditions do not apply, (case 2) Figure 8 flow chart applies. Figure 8. Key test explanation: Test (A) Test (B) Test (C) Test (D)

Packer fluid is a high specific gravity fluid (> 1.6 kg/l) with possibility of solids settling. Max well deviation >20 deg. Tubing pullout foreseen high frequency (completion life < 5 years). Packer is mechanically set.

In Figure 8, exit conditions from both rectangles indicate, besides the tubing-packer connection selection, the need of utilising the specified packer setting procedure, possibly superimposing this to previous selections made. As for a moving seal element, in general no further modifications are recommended whenever a failure of stress analysis is encountered. For a deviated well is so not recommended an anchored tubing-packer connection; it is preferred, whenever feasible, a tubing-packer connection provided with a shearing element (easier to decouple), or a moving seal.


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TEAP-P-1-R-8794 5.4.5

TUBING-PACKER CONNECTION

5.4.5.1

PACKER RETRIEVABLE

Tubing-packer connection selection for packer retrievable (hydraulic and set down weight) should be done according to Figure 9 flow chart. (Hydraulic packer)

(Set down weight packer)

Stress Analysis

Anchor

Stress Analysis

Failure

(A)

Choice (1)

Telescopic Joint

Choice (2)

PBR

(2)

Packer Retainer

(1)

Packer Permanent Retrievable

Figure 9. Connection tubing-packer for retrievable packer

The presence of a particular set of conditions can lead to ridiscuss the original Retrievable packer selection. In these cases, the engineer is driven to select a PermanentRetrievable (first priority) or Retainer packer; as a consequence the corresponding setting sequence (see paragraph 1.3.2.1) and seal assembly selection (see paragraph 1.3.3) shall be adopted.


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SINGLE SELECTIVE COMPLETION PACKER

Criteria fixed in this paragraph are valid for multiple single selective completions. In particular, solutions presented refers to a dual zone single selective completion; when considering more zones, each further upper zone shall be dealt as the ‘upper zone’ of the dual zone completion.

5.5.1

PACKER TYPE SELECTION

First case characterises the well in terms of total depth (4000 m plus) and in terms of its ‘complication’. Following selection criteria apply if one of following conditions is verified: • • • • •

Corrosive well Well measured depth > 4000 m. SBHT > 130 °C SBHP > 700 atm. Offshore, subsea well

Packer Retainer with Anchor and Mill Out Extension (MOE)

Figure 10. Single selective. Extreme Well Packer When multiple configurations are possible, as in Figure 10, the engineer has one choice available; which is in any case regulated by the priorities fixed . When Figure 10 does not apply, wells are classified considering their total depth (measured).

Packer Retainer with Anchor and Mill Out Extension (MOE)


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Hydraulic Packer Retainer/Retrivable

Figure 11. Single selective. Well measured depth between 3000 and 4000 m.


Figure 12. Single selective. Well measured depth between 1500 and 3000 m.


Figure 13. Single selective. Well measured depth between below 1500 m. When well depth is below 1500 m. (Figure 13) in a simple well, it is strongly recommended to install a packer Retrievable. Application of Figures 9 - 13 is general; the only exception can be to modify as follows the priority selection for the Lower Zone: •

If a workover with tubing and packer pullout is foreseen and among the possible choices is possible the installation of a retrievable packer, select this one.

•

If the completion fluid is a heavy mud with possible solid deposition problems and among the possible choices it is possible the installation of a Retainer or a Permanent Retrievable packer, select this last one instead of the upper retrievable.


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5.5.2

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PACKER SETTING METHOD SELECTION

Proposed packer setting method depends on: • •

Packer type Distance between packers.

Setting criteria for a Mechanical Retainer packer (by Workstring, by Wireline) are those set for the single completion (see paragraph 1.3.2).

5.5.2.1

ALL PACKERS RETAINER (FIGURE 10)

If distance between packers is greater than 500 m. (this distance to be confirmed by packer manufacturers, then select all Hydraulic set packers, otherwise consider mechanic set.

5.5.2.2

ONLY THE REFERENCE PACKER IS RETAINER (FIGURE 10, FIGURE 11, FIGURE 12)

In this case other packers are either Retrievable or Permanent Retrievable; for both, when completion fluid is a brine, setting sequence should be preferred, otherwise mechanic setting can be accepted. For the reference packer the mechanic setting is preferred, providing this is done by electric line when the distance between packer is less than 500 m. When reference packer is set by workstring, it is necessary to verify the packer setting depth, to guarantee the correct blast joint positioning with respect to the upperproduced zone. 5.5.2.3

ALL PACKER RETRIEVABLE (FIGURE 12, FIGURE 13)

As defined in paragraph 1.4.2.2, for these packers the hydraulic setting is preferred. It is necessary to verify with manufacturers that distance between packers is above the minimum required for their proper setting. 5.5.3

TUBING-PACKER CONNECTION SELECTION

Criteria classify the packers per type and setting sequence; zones are considered separately. In some cases zones are distinguished (Upper, Intermediate, Lower); when not specifically mentioned, instead, the Intermediate Zone is considered similar to the Upper Zone. Whenever the stress analysis would fail, indications are supplied to solve the problems. Generally, the stress analysis indicates those packers which could present unsetting problems; also in this case, zones will be considered separately, and modifications recommended for those packers failing in staying set. It is good practice in these cases to re-verify the entire completion.


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IDENTIFICATION CODE

23

OF

23


5.5.3.1

PAG

0 1

UPPER PACKER

Same indications supplied for the single completion apply (paragraph 1.3.3.3 e paragraph 1.3.4). 5.5.3.2

LOWER AND INTERMEDIATE PACKER

When dealing with the Lower zone for two or three zones, three different scenarios could occur: •

All packers are Retainer/Permanent-Retrievable type, hydraulic set: initial selection would then be for a ShearRelease Anchor; in case of stress analysis failure next selection would be for a moving seal assembly (Anchor with PBR or telescopic joint).

•

Lower zone packer is Retainer mechanic set: a moving seal is the logical recommendation, in particular it should be a Standard (short) Locator; in case of stress analysis failure, a Long Locator complete with Seal bore extension is the alternative. In case of an intermediate zone in a three zones completion, the recommended connection to the intermediate packer is an Anchor.

•

Lower zone packer is Retrievable; in case of stress analysis failure the alternative is a moving seal with telescopic joint. In case of an intermediate zone in a three zones completion, recommended connection to the intermediate packer is a Telescopic Joint.


ARPO



TYPE OF ACTIVITY'

ISSUING DEPT.

DOC. TYPE

REF. N.

OF

TEAP

P

1

R

1

PAG.

52

8795


Volume 1

CHAPTER 6 - SURFACE WELLHEAD DISTRIBUTION LIST TEAP STAP – Archive



Date of issue: 30/01/98 „ ƒ ‚ •


€

Issued by

REVISIONS

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



PREP'D

CHK'D

APPR'D


ARPO


IDENTIFICATION CODE

PAG

2

OF

52


0 1

INDEX 6. SURFACE WELLHEADS................................................................................................................3 6.1 GENERAL .................................................................................................................................3 6.2 WELLHEAD CONFIGURATION ................................................................................................4 6.2.1 WELLHEAD AND CHRISTMAS TREE RATINGS............................................................4 6.2.2 STACKED WELLHEADS .................................................................................................8 6.2.3 COMPACT (UNITIZED) WELLHEADS...........................................................................11 6.2.4 QUICK CONNECTORS..................................................................................................12 6.3 CHRISTMAS TREE CONFIGURATION...................................................................................12 6.3.1 COMPACT TREE...........................................................................................................12 6.3.2 SPLITTED TREE ...........................................................................................................13 6.3.3 COMPOSITE TREE .......................................................................................................13 6.4 VALVE CONFIGURATION ......................................................................................................13 6.4.1 SLAB GATE ...................................................................................................................13 6.4.2 EXPANDING GATE .......................................................................................................14 6.4.3 ACTUATORS CONFIGURATION ..................................................................................15 6.4.4 HYDRAULIC...................................................................................................................15 6.4.5 PNEUMATIC ..................................................................................................................16 6.5 SPECIAL APPLICATIONS ......................................................................................................16 6.6 REFERENCE SPECIFICATIONS ............................................................................................17


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IDENTIFICATION CODE

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3

OF

52


6.

PAG

0 1

SURFACE WELLHEADS

GENERAL

The system composed by the surface wellhead and the christmas tree is one if not the most important component of the well from the safety point of view. Infact, besides being the interface between the topside network/treatment plant and the well, they compose the system which guarantees the well integrity towards the external environment and as such act as the main safety barrier. Wellhead is the ‘drilling’ part of it and guarantees the suspension of the casing system while running it and its anchorage when cemented; in particular through its components it transfers the loads (tension, compression and temperature) coming during production from the production casing and from the christmas tree to the casing suspension system which then transfer it to the ground onshore or through the environmental conductor to the offshore structure. The system integrity is vital for the well integrity, even if back up system are in place in case of abnormal malfunctioning/blasting, also because is the more operated system in a well, and its functionality shall be granted throughout the well life.


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IDENTIFICATION CODE

4

OF

52


6.2

PAG

0 1

WELLHEAD CONFIGURATION

Surface wellhead configurations have been modified through the years starting from very simple configurations to very complicated ones; this dependig mainly on rating required which, due to increased difficulty of wells to be drilled, is continuosly grow up. Today several installations have been done onshore and offshore with 15000 psi Working Pressure trees and 20000 psi WP, already designed in the past, are now being manufactured on a larger scale. API has always ruled on wellhead and christmas tree specifications but its rules are valid only for flanged configurations, or stacked spool wellheads. In the last five to eight years there has been a great push, expecially in the North Sea for offshore applications, to develop and install compact (unitized) drilling wellheads. Their application, together with the use of compact trees, offers the main advantage of total wellhead height reduction, which has a big impact in reducing the clearance between floors of offshore platforms, with an evident CAPEX reduction in offshore structures. Together with this development a great operational improvement has been obtained with the use of ‘quick connectors’ to replace the API flanging. Their use, derived from subsea applications, has greatly reduced the nipple up/down time expecially when dealing with offshore BOP and risers systems. Installation time has passed with this new design from hours to minutes, not diminishing or jeopardizing at all the overall safety consideration. The next step will be for the use of ‘Horizontal’ or ‘Spool Tree’ derived form subsea design for platform installation or of multiple compact wellhead installed inside the same conductor to save offshore deck space. Already done, even if not very common, the manufacturing of wellhead and Xtree whose rating is outside the API rules (without API stamp) for classes of working pressures in between the conventional API classes (i.e. 7500 psi WP). Agip experience is quite differentiate, depending on the geographic area where they are applied. In Italy All installation are with stacked API wellheads ranging from 5000 psi WP to 15000 psi WP, single and dual wells; North Africa Agip Overseas Companies use stacked API wellheads ranging from no naturally flowing wells (ESP applications) to 10000 psi on single wells, onshore and offshore. West Africa Agip Overseas Companies use conventional wellhead 5000 and 10000 psi for single and dual wells and ESP 3000 psi Unitized Wellheads applied in slant wells (30 deg inclination at surface) Agip Uk applies in the North Sea Unitized 5000 psi dual compact tree wellheads. Chapter 6 list internal Company Reference Codes.

6.2.1

WELLHEAD AND CHRISTMAS TREE RATINGS

6.2.1.1

PRESSURE RATING

First important step when designing for a wellhead is the system pressure rating statement. Agip document STAP M 1 V 5011 fixes the criteria for determining the dowhnole equipment rating. The document has been written for Safety Valves; nonetheless it can be applied to wellheads too and for convenience it is here below summarized: WORKING PRESSURE is defined as: A.1. W.P. = STATIC BOTTOM HOLE PRESSURE (SBHP) 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


IDENTIFICATION CODE

PAG

5

OF

52

REVISION 0 1

TEAP-P-1-R-8795

or A.2. W.P. = MAX STATIC TUBING HEAD PRESSURE x SAFETY FACTOR Where: S.F. = 1.1 In Oil Wells S.F. = 1.3 In Gas or Gas/Condensate Wells Utilization of definition A.1 or A.2 follows tab.1 and fig.1. (For explanations of tags used refer to API 6A). 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

SBHP SBHP


ARPO

IDENTIFICATION CODE


PAG

6

52

OF

REVISION 0 1

TEAP-P-1-R-8795 Figure.1

STA RT HERE

STA TIC BOTTOM HOLE PRESSURE > 10000 PSI

Y ES

HIGH H2S CONCENTRA TION ?

Y ES

SBHP

NO NO CLOSE PROXIMITY?

Y ES

SBHP

SBHP

NO > 5.000 PSI Y ES NA CE?


Y ES

Y ES STA TIC BOTTOM HOLE PRESSURE

SBHP

CLOSE PROXIMITY? NO

SBHP <=5.000 PSI Y ES

NO

NO

SBHP

CLOSE PROXIMITY?

NO

STHPxS.F.

Y ES CLOSE PROXIMITY?

STA TIC BOTTOM HOLE PRESSURE

> 5.000 PSI

<= 5.000 PSI

SBHP

STHPxS.F.

NO STA TIC BOTTOM HOLE PRESSURE

> 5.000 PSI

STHPxS.F.

> 5.000 PSI <= 5.000 PSI STA TIC BOTTOM HOLE PRESSURE

CLOSE PROXIMITY?

Y ES

STHPxS.F. SBHP

NO <= 5.000 PSI

STHPxS.F. STHPxS.F.


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IDENTIFICATION CODE

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Figure 1 Explanations 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:


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IDENTIFICATION CODE

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8

OF

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0 1

X = [(0.4546) (mole fraction H2S) (Q)]0.6258 Where: X = Radius of exposure in feet 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 urrent 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.

6.2.1.2

TEMPERATURE RATINGS

For temperature ratings the definitions specified in API 6A Table 4.2 apply. 6.2.1.3

MATERIAL REQUIREMENTS

For Material Class requirements the definitions of API 6A Table 4.3 apply, Since these definitions only identify the material class, refer to Corrosion and Material Selection chapter of this book to find complete list of material of individual components of those part usually in contact with produced fluids. 6.2.2

STACKED WELLHEADS

This is the most conventional configuration (fig 2), following API rules..

6.2.2.1

BASE FLANGE

The configuration starts with the base flange (fig 3) which was usually welded to the conductor pipe and nowdays can be of the ‘slip on’ type; this new configuration avoids welding operations with preheating at the well site and saves rig time; it also allows in offshore installations for a more convenient alignment system with platform flowlines inlet. The base flange is the element which transfers the overall wellhead loads to the ground directly (onshore) or through the enironmental conductor pipe (offshore). 6.2.2.2

CASING SPOOLS

The system generally follows with a series of flanged casing spools (fig 4) rated per API 6A from 2000 psi to 20000 psi; number of spools depends on well drilling profile and accounts for all casing 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


IDENTIFICATION CODE

PAG

9

OF

52


0 1

which will be run at surface. The individual casings are suspended by means of slips or mandrels. (fig 5) Slips are used when there is the need to pre-tension the casing string after cementig only the botoom part of it and, due to temperature increase of the wellbore during production, a casing elongation of its free section is foreseen. Mandrels (Casing Suspension Hangers) are used elsewhere where either the wells are colder or the cement job is performed up to surface. (fig 6) In casing spools with slips, they land on special load shoulder; the sealing around the relevant casing and the spool ID is done by means of two elastomeric set of packings: the primary packing assembly which seals in the upper part of the lower spool around the casing; the secondary packing assembly which seals in the lower part of the upper spool around the same casing size. Sealing action is obtained by radial interference. The individual casing hangers are retained in position by radial anchor screws. In casing spools with mandrels the sealing is granted by a pack-off system, which seals between the top part of the mandrel and the spool ID. In both cases each sealing area shall be provided with its independent test and vent port, rated for the same pressure of the spool they are part off. Pressure rating of casing spools increases from the base flange to the upper casing spool as a function of the pressure gradients the casing column they should suspend will have to withstand. Each spool is provided with two flanfes: the lower one rated for the lower pressure rating it has to contain as well as the body; the upper one rated for the next spool pressure rating: In case of abnormal variation of rating throughout the spool, special Crossover spool with special packing assembly can be provided. The last casing spool, rated for the full well pressure, generally suspends the production casing, and seals around it with the primary packing assembly. Below the primary seal assembly all casing spools are provided with two outlets (normally 2” nominal) which allows for the annulus control and monitoring; in particular one outlet is usually provided with a flanged gate valve; the other outlet with a flange and a monitoring gage. 6.2.2.3

TUBING SPOOL

On top of the last casing spool it is mounted the tubing spool (fig 7) which, rated for the maximum well pressure and made of the proper class of material, has the function of suspending the completion, providing a load shoulder for the tubing hanger. The tubing spool seals around the production casing either with the secondary packing assembly or with a metal pack-off when this is required. See par 5.5 item 4. As well as the casing spool it is provided with two outlets (normally 2” nominal) which allows for the annulus control and monitoring; in particular one outlet is usually provided with a flanged gate valve; the other outlet with a flange and a monitoring gage.


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IDENTIFICATION CODE

10

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6.2.2.4

PAG

0 1

TUBING HANGER

The completion is suspended inside the tubing spool by means of the tubing hanger (fig 8 a-b-c-d); the tubing hanger seals inside the tubing spool either with the an elastomer pack-off assembly or with a metal pack-off when this is required. See par 5.5 item 4. The tubing hanger also shall be anchored inside the tubing hanger to avoid that, during production it can be lifted off by the tubing string elongating for temperature increase; this is usually accomplished by tie-down screws which radially act on a conical shaped ring which at the same time energize the tubing hanger pack off.seals. On its top the tubing hanger can be manufactured in different shapes: - in its simplest version it can have a solid neck which intrudes inside the bonnet where ‘O’ rings segregates circumferential galleries for Safety Valve/s control line/s hydraulic control fluid - in other cases, the control lines have separate outlets through the hanger; so their continuity as well as the continuity of the main bore with the bonnet is granted by transfer carriers which seals inside the hanger body and inside the bonnet body; these transfer carriers can be provided with elastomeric ‘O’ rings or with metal seals (crash rings usually done with a softer plastic stainless steel) when required. See par 5.5 item 4. The tubing hanger internal profile always foresee either for a seat for the Back Pressure Valve or better for a wireline plug, in many modern installations. Both devices have the scope of plugging the production tubing before removing the X-mas tree and nippling up the BOPs. The advantage of the wireline plug against the use of the BPV, is its possibility to be run or retrieved under pressure using normal wireline pressure equipment, while the retrieval of BPV under pressure requires the use of special tools.

6.2.2.5

RING JOINTS/GASKETS

Ring Joints are the sealing elements between flanges. They are put in specially machined grooves on the flange face and plastically deforms when flanges are nippled up. There are three different type of ring joints: R, RX, BX Type R and RX are used with flanges type 6B. Flanges type 6B dimensions are defined in API 6A tables 10.2, 10.3, 10.4. They are not designed for face-to-face make up; that is to say that bolt correct tensioning is enough to grant for ring joint energization and no flange face load is foreseen. Their maximum allowabel working pressure rating is 5000 psi from 2 1/16” up to 11” size, 3000 psi from 2 1/16” up to 20 3/4”, 2000 psi from 2 1/16” up to 21 1/4” Type BX gaskets are instead used for raised face flanges type 6BX whose dimensions are defined in API 6A tables 10.6 to 10.11. They are designed for face to face make up; that is to say that bolt correct tensioning, besides energizing the ring joint, loads the flange face to withstand heavier bending moments and to accomodate for possible bolts elongations due to high temperatures Depending on flange size and application, their maxximum allowable working pressure rating ranges from 2000 to 20000 psi. Due to their face to face connection the machining tolerances of their faces are stricter than for type 6B flanges.


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IDENTIFICATION CODE

11

OF

52


6.2.2.6

PAG

0 1

BOLTS

Bolts and nuts or studs and nuts are the connecting media between flanges. Material class for bolts are defined in API 6A as well as recommended make up torque (Apendix A), which is given for different friction factors between bolts and nus bearing surfaces. In general terms the recommended value is for tensioning bolts not more than 50% of their material Yield. The correct tensioning of bolts is nonetheless very difficult to correlate to their applied torque since, besides different terms considered in API equation depends also on nuts and flange surface friction factor which is completely ignored in the API formula. Tests done in hose have demonstrated that, even using a calibrated hydraulic torque wrench therew can be a tension variation among all the bolt of a flange of plus or minus 40 %, which can not be accepted, expecially ina high pressure rating applications. For this reason a complete set of tensioners, to be applied simultaneously on the mating flanges, has been designed for different size of bolts/flanges to have a more uniform distribution of load on the bolts of the flange. In this case the bolts, which should have an extra legth, with respect to the API one, equal to the bolt OD for the tensioner device make up, are simultaneously tensioned hydraulically. The applied pressure stretches the bolts to a value slightly higher than its optimum tension, to take into account for its extra leght of the blolt; the bolt is then manually made up to mate the flange face and hydraulic pressure released. In house testing have demonstrated that the tension variation among all the bolt of a flange, using this method can be reduced to plus or minus 5 %. Documentation referred in par 5.5 is available for application. (fig 9-10)

6.2.3

COMPACT (UNITIZED) WELLHEADS

Compact wellheads are not a recent develolpment only. Agip is using them extensively in Congo from the seventies in the 3000 psi WP version for ESP wells (see 5.6). New concept of compact (Unitized) wellheads has yet been developed with other purposes (fig 11); their application, together with the use of compact trees, offers the main advantage of total wellhead height reduction, which has a big impact in reducing the clearance between floors of offshore platforms, with an evident CAPEX reduction in offshore structures. Also, their use allows to minimize connections; infact in a 20”, 13 3/8”, 9 5/8”, 7” casing programme, it reduces connections from 5 flanges to two quick connectors, with clear advantages in term of probabilistic leak paths. Another feature is the elimination of tie-down screws to lock the different hangers (csg and tbg) and their substitution with lock ring derived from subsea wellheads application. Usually the wellhead has a lower body 21 1/4” 2000 psi WP for anchoring the 20” casing, and a main body 13 5/8” 5000 or 10000 psi WP which accomodates all casing hangers and the tubing hanger. Casing hangers and tubing hangers can have different configurations, stacked one on top of each other resting on independent load shoulder, or stacked on top of each other, or nested. In the first issue each hanger being telescopically larger than the previous one, needs its own individual pach off; in the second configurations all hangers OD are the same, the body has the same ID and the pack off are all the same; in the third option, the more compact, at least the tubing hanger rests inside the last casing hanger. All of them have advantages and disadvantages which shall be well evaluated from an operational point of view before making the right selection. Agip specification mentioned in chapter 6 has been written to accomodate for most of tese considerations. 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


IDENTIFICATION CODE

12

OF

52


6.2.4

PAG

0 1

QUICK CONNECTORS

Together with the development of unitized well heads a great operational improvement has been obtained with the use of ‘quick connectors’ (fig 12) to replace the API flanging. Their use, derived from subsea applications, has greatly reduced the nipple up/down time expecially when dealing with offshore BOP and risers systems. Installation time has passed with this new design from hours to minutes, not diminishing or jeopardizing at all the overall safety consideration. Designed in different proprietary configurations and specifications, these connectors have been derived from subsea applications and usually, can grant higher bending resistance than the corresponding flange size. Their design is conceived to allow the two mating parts alignment while mating, due to the important swallow lenght of the connectors. Sealing is granted by metal to metal devices, different from API gaskets; these devices have proprietary suppliers design characteristics but in general terms, they achieve the sealing action through elastic radial deformation of metallic lips or through crash ring deformation due to wedging actions. These connectors acts on hubs whose shape is derived from the original API clamps which nowdays are no longer mentioned in API 6A.

6.3

CHRISTMAS TREE CONFIGURATION

The tree is the real safety device which intercepts the flow from the well. Its traditional configuration consists above the Bonnet, which connects the tree with the tubing spool, of: Vertical flow path - a Lower Manual Master Valve - an Automatic (remotely controlled) Master Valve - a Cross - a Manual Swab Valve - a Tree Cap with Quick Connector for the wireline lubricator Horizontal flow path (departing from the cross) - an Automatic Wing Valve - a Chemical Injection/P&T pockets block - a Chocke Valve (usually covered by Topside Engineering) - Xover to the flowline connection - a Manual Kill Valve (opposite side of the cross - optional) - a quick hammer type connection (optional) 6.3.1

COMPACT TREE

Compact tree is a tree where usually the functions listed under Vertical flow path are all machined inside the same forging block, saving lot of flanged connections and saving total overall dimensions; in general terms the row material cost saving is compensated by a greter manufacturing cost


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IDENTIFICATION CODE

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13

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(expecially if internally cladding is necessary) so that the overall cost is not going to decrease: the real benefit is so the possible leak path reduction. From an operational poin of view the maintenance cost of such a type of tree is generally greater than the one of composite type. To avoid or reduce such type of problems, and expecially in critical wells (HP/HT, inclad tree), Bonnet and Lower Master can be incorporated in the same block which in this case it is called Seal Flange. Several configuration of trees are available and here following are few illustrations. 6.3.1.1

SINGLE TREE

See fig 13. 6.3.1.2

DUAL TREE

See fig 13. 6.3.2

SPLITTED TREE

6.3.2.1

SINGLE TREE

See fig 14.a-b 6.3.2.2

DUAL TREE

See fig 15. 6.3.3

COMPOSITE TREE

See fig 2.

6.4

VALVE CONFIGURATION

Valves for Xmas Tree are of different configuration mainly with respect: to the closure system: - Floating Slab Gate - Expanding Gate or to the stem type: - Rising/Non rising stem - Balanced/Non balanced stem 6.4.1

SLAB GATE

Slab gate valve (fig 16) seats are generally manufactured in special hardened steel or protected with corrosion resistant materials. Each seat is provided with one frontal TFE ring and one ‘O-ring’ 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


IDENTIFICATION CODE

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14

OF

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on the cylindrical external surface. The TFE ring (fig 17-1) assures a temporary seal between seats and gates during the opening or closing of the valve and provides for gate cleaning. With the valve in closed position (side 1under pressure) due to the thrust generated on the surface A of the gate (fig 17-2) a force F1 pushes the gate itself towards the seat (side 2) so as: 1. to move the seat towards the valve body so realizing the seal between seat and valve body for deformation of the ‘O-ring’ O2. 2. to deform the T2 teflon ring to realize the metal to metal seal between gate and seat. Should the valve body pressure bleed off for pressure differential, then the ‘O-ring’ o1 will provide for the seal between seat and body. in addition a differential thrust will occur on the surface B and a such as to give rise to a force F2 which will deform the T1 teflon packing, causing the metal to metal seal between seats (fig 17-3) Should, during service, the valve body pressure exceed the line pressure, the peculiar design of the seat prevent the valve body from damage. Infact the differential thrust betweensurface A and B (fig 17-4) give rise to a force F3 which causes the moving back and consequently the discharge of the overpressure in the line. The particular size of the gates permits these valves to be equipped with hydraulic and pneumatic actuators ‘fail close’ in wellhead use. Lack of control pressure in the actuators, will cause the actuator spring to close the valve helped by the well pressure if present. All closure of these valves will cause the backseat on the stem to seal. In the most advanced versions of these valves, for corrosive and/or high pressure/fire safe applications metal elastic rings replace the ‘O-rings’ while seat to gate surface are lapped. Valves for application at working pressure above 5000 psi are provided with balanced stem, because this eliminates the hydrostatic thrust on the stem itself and ease the operations. The axial thrust on the stem is supported by two taper roller or ball bearings which minimize the operating torque; the stem seal is given by plastic chevron packing for normal application, it has a special configuration in fire safe valves. They are available as rising stem or not rising stem.

6.4.2

EXPANDING GATE

Expanding gate valves (fig 18) are provided with two parallel expanding gates (fig 19) retained together by a spring, which, moving on the opposite cones, expands to mate the seats, granting a tight seal upstream and downstream and isolating the body from the flowing pressure. Flow helps in forcing the two seats to better close. Since the valve is wedged also in open position, usually this type of valve is not provided with an affective backseat. In its intermediate position the gate does not exerts any appreciable pressure on the seats. The axial thrust on the stem is supported by two taper roller or ball bearings which minimize the operating torque; the stem seal is given by plastic chevron packing for normal application, it has a special configuration in fire safe valves. Valves for application at working pressure above 5000 psi are provided with balanced stem, because this eliminates the hydrostatic thrust on the stem itself and ease the operations. (fig 20) This kind of valve is not usually applicable for automatic actuaded applications. 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


IDENTIFICATION CODE

PAG

15

OF

52


0 1

Nowdays is very seldom used in xmas tree applications and tends to be substituted by slab gate valves which are also more economical in cost. They are available as rising stem or not rising stem. 6.4.3

ACTUATORS CONFIGURATION

Actuator design for Xmas tree application is covered by API 6A either for engineering or for testing and quality control 6.4.4

HYDRAULIC

Hydraulic actuators are used in production wells to automatically shut in the well at surface in the event of a flowline leak, fire or explosion at the wellhead, abnormal pressure fluctuations or critical fluid level in surface equipment.

6.4.4.1

FAIL SAFE

Hydraulic actuators (fig 21 a-b-c) use hydraulic fluid (control fluid) as external source to move a piston counterbalanced by a spring which, when hydraulic power would be removed (see at this regard chapter 6.2.2), will cause the gate valve to fail safe close; properly sized coil springs provide a reliable return stroke to close. The new design of actuators usually allows easy conversion in the field of manual gate valves to automatic. Sound engineering practics in selecting an actuator should look to the exposure of seals to the environment and on the correct coating of surfaces contacted by saline offshore atmosphere. Also a look should be placed to the volume of hydraulic fluid needed to operate the actuator. Big volumes means long closure times due to the return line friction losses expecially offshore where control cabinets are usually far from the wellhead area.

6.4.4.2

FAIL SAFE /WIRE CUTTING

Several installation uses directly on the tree master valve the wire cutting actuator, while other operating companies prefer not to use this costly actuator on each Xmas tree but use it on an actuated spool valve mounted below the wireline/coil tbg lubricator when this is installed for servicing. This kind of actuators enables operators to comply with legal requirements for two barriers across every conduit during workover/well servicing operations. To cut wireline or coil tubing this type of actuator shall incorporate devices that store supplemental energy and release it for the cut. Different configurations are available; the one shown is probably the most original one present on the market. Hydraulic control pressure is applied to telescopic pistons which cause the gate valve to move to the open position. Loss of hydraulic pressure allows the transverse spring, plus valve internal pressure, to act acrioszs the cross sectional area of the stem and to force the gate to the closed position. The


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transverse springs, provide up to 8000 lbs force at the end of the stroke, which is considered sufficient to cut 7/32” braided wire and to close the gate regardless of the well pressure in the valve body: special design needs to be required for coil tubing cutting. Qualification tests need to be done to verify gate ability to seal after the cut. (fig 22 a-b-c-d)

6.4.5

PNEUMATIC

Pneumatic actuators use instrument air as control fluid as external source to move a piston counterbalanced by a spring which, when air would be vented (see at this regard chapter 6.2.2), will cause the gate valve to fail safe close. Due to the reduced pressure at which air is distributed they usually require large piston area which increases the installation overall dimensions and sometimes makes this not acceptable. Generally speaking their application is more frequent on single on land applications. (fig 23 a-b-c-d)

6.5

SPECIAL APPLICATIONS

Special configuartions can be defined those utilized for ESP applications where the important thing to note is not the Xmas tree rating but the configuration itself to accomodate the passage for the electrical cable providing all the safety features required to install and remove the Xmas tree itself (fig 24 a-b)


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REFERENCE SPECIFICATIONS

1. API Specification 6A - 17th Edition, Feb 1, 1996 2. 3. STAP M 1 SS 5702 - UNITIZED SURFACE WELLHEAD AND CHRISTMAS TREE EQUIPMENT 4. STAP M 1 M 5004 - WELLHEAD AND CHRISTMAS TREE GUIDELINES FOR METAL TO METAL SEALS USE 5. STAP M 1 M 5011 - PROCEDURE FOR API FLANGE ASSEMBLY USING STUD TENSIONERS 6. ASME BOILER AND PRESSURE VESSEL CODE. SecVIII, DIV 2 APP 4


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TEAP-P-1-R-8795 Figure 4

Figure 5

Figure 6

Ø 33 6 .5

A

A 5

EY E B O L T

F e 5 10

002 700 006 30 4

2

4

P IN

S TE E L

002 574 300 00 4

4

3

S C R EW 1 / 2 " U N C

A S TM A 19 3 - B 7

002 531 830 557

2

2

S P ID E R B O D Y

1

S L IP

A c c .2 0 N iC r M o 2

002 700 008 04 3

IT E M

D E S C R IP T I O N

M A T E R I AL

CO D E

13 5 . 3

SE C T I ON

A- A

AISI 4 130

1


1 Q.

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Figure 8a


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Figure 8b


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Figure 8c


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Figure 8d


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Figure 9


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Figure 10


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Figure 11


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Figure 12


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Figure 13


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Figure 14a


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Figure 14b


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Figure 15


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Figure. 16


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Figure 17


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TEAP-P-1-R-8795

Figure 18 ITEM 1 2 3 4 5 6 7 8 9 27

10 11 12 14

DETA IL A

15

DET AIL A

DETAI L B

DE TAIL C

DETAIL D

16

DETA IL B

17

DETA IL C

18

DETA IL D

19 20 21 22 23 24 25 27 28


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Figure 20


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Figure 21a


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TEAP-P-1-R-8795

SEE DRAWING B HW

LIMIT SWI TCHES - type "GO SW ITCH"

21

DETAIL A

74 75 18

DETAIL B

DETAIL A

DETAIL B

DETAIL C

DETAIL D

16 17

DETA IL C

15

DETA IL D

20

22 23 24 25

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Figure21b


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Figure 21c


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Figure22a


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Figure 22b


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Figure22c


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Figure 22d


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Figure 23a


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Figure 23b


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Figure23c


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Figure 23d


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Figure 24a


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Figure 24b


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TYPE OF ACTIVITY'

ISSUING DEPT.

DOC. TYPE

REF. N.

OF

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P

1

R

1

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24

8796


Volume 1

CHAPTER 7 - SAFETY VALVES & MISCELLANEOUS DISTRIBUTION LIST TEAP STAP – Archive





€ Issued by REVISIONS

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



PREP'D

CHK'D

APPR'D


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INDEX 7. SAFETY VALVES AND MISCELLANEOUS ...................................................................................3 7.1 SAFETY SYSTEMS ..................................................................................................................3 7.1.1 GENERAL........................................................................................................................3 7.2 TUBING SAFETY SYSTEMS ....................................................................................................3 7.2.1 VALVE CONTROL SYSTEM............................................................................................3 7.2.2 SURFACE CONTROLLED VALVES................................................................................3 7.2.3 FLOW CONTROLLED SAFETY VALVES .......................................................................7 7.3 VALVE CLOSURE MECHANISM ..............................................................................................8 7.4 SAFETY VALVE CONFIGURATION .........................................................................................9 7.5 EQUALIZATION ......................................................................................................................12 7.6 ANNULAR SAFETY SYSTEMS...............................................................................................14 7.7 REFERENCE STANDARDS....................................................................................................14 7.7.1 STANDARDS .................................................................................................................14 7.7.2 OPERATIONAL TESTING FREQUENCY ......................................................................18 7.8 ENGINEERING PROCESS FOR SELECTION OF THE SURFACE CONTROLLED SUBSERFACE SAFETY VALVE...................................................................................................18 7.9 DOWNHOLE SAFETY VALVES - INSTALLATION GUIDELINES ..........................................22 7.9.1 APPLICATION ...............................................................................................................22 7.10 VALVE TYPE ........................................................................................................................22


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7.

SAFETY VALVES AND MISCELLANEOUS

7.1

SAFETY SYSTEMS

7.1.1

GENERAL

0 1

Safety is of paramount importance inside any completion design and is the main consideration the engineer should take into account during design. Safety in general terms means being able to guarantee the completion integrity of the designed completion in any of its components throughout the different load cases its operating life will face; this is done applying the most convenient safety factors to the individual components or verifying they are applied. This can be defined as intrinsecal design safety. In addition, a minimum number of safety barriers shall be installed to guarantee that the well remains safe in case of wellhead disruption, and basically these are the downhole safety valve and the wellhead itself. In this respect, attached documents, issued by Agip STAP (Standard and Procedures) give Company guidelines on type of Safety Systems required as function of well severity and of Safety Valves internal main features required for different pressure ratings.

7.2

TUBING SAFETY SYSTEMS

7.2.1

VALVE CONTROL SYSTEM

Downhole Safety Systems can be divided into two main cathegories with relevant sub-cathegories from the point of view of valve control. 1. Surface controlled (hydraulic)

- Tubing Safet Valves - Annulus Safety Valves

2. Flow controlled

- Rate controlled - Pressure controlled

* Annular systems * Vent Systems *Water Injection Wells *Production wells

Basic difference between the two main cathegories is the operator control of the valve closure mechanism. 7.2.2

SURFACE CONTROLLED VALVES

In this case the control is hydraulic (by means of hydraulic oil) through a permanently installed 1/4” OD control line which at surface is connected to a hydraulic cabinet and is held open under the operating opening pressure. The hydraulic pressure acts against a spring, holding the valve open; any control line rupture or any fire (melting a plug of control circuit - figure 1) opens the control circuit to atmosphere venting the control line pressure and causing the valve to fail safe close by means of the spring. Valve of this type are available in the wireline and tubing retrievable configuration (figure 2,3).


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Figure 1. Concentric pistons valve


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Figure 2. Wireline retrievable SCSSV with saeting nipple (not in scale)


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Figure 3. Tubing retrievable SCSSV


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- Setting depth Setting depth of these valves is a compromise between the hydraulic gradient in the control line and the reaction force available from the spring according to following equation:

D= C* where:

F A*G

D = Failsafe closure depth, ft F = Spring force with valve closed, lbs A = Area of piston, in2 G = Maximum fluid gradient, psi/ft C = Safety factor, usually 1. 2

The above equation assumes evacuated tubing (no pressure inside tubing). In reality the wellbore pressure, acting on the piston area, assist the valve to close. Hence the opening pressures of valves are quoted as X psi above tubing shut in pressure; the larger the piston area, the greater the assistance from the wellbore. In real terms, such kind of valves have not been set deeper than 1000 m, due to restriction in spring material availability. - Surface System In most of Agip installation worldwide the adopted control system, either at the well for surface individual installation or offshore for mutiple installations, is similar to figure 4, where both the master and the wing valve actuators are hydraulic; the remote panel consists of a cabinet containing a reservoir of hydraulic fluid kept under pressure by a triplex pump and the system vent is achieved automatically when: - a leak is experienced in the control line system - Hi-Low pilot sense high low pressure inside the flowline (plugging or break-out) - fusible plugs melt - the emergency shut down button is pushed Generally each well is controlled automatically but its control can be switched to manual for wireline, workover interventions. In subsea application instead, the high pressure is supplied to the Control Pod which then drives the safety valve/s: different Emergency Shut Down procedures can vent the hydraulic pressure from the control line generally to a subsea relief vessel to avoid that elevated back pressure in the umbilical line causes non acceptable long closure times.

7.2.3

FLOW CONTROLLED SAFETY VALVES

In this case there are two different configurations for injection wells or for production wells. - Injection Wells In injection wells the valve is normally closed to prevent back flow of the well, and is operated to open by means of the pressure drop occurring across a predetermined choke (function of injection rate expected) positioned inside the flow tube which acts against the spring.


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Any pressure drop in excess of the predetermined one will keep the valve open; while any pressure drop below the predetermined one will allow the valve to close by means of the return spring. Valve with this characteristics are available only as wireline retrievable valves.

Figure 4. Remote and direct controlled safety system - Production Wells In production wells, instead, the valve is normally open and set for foreseen rates; when the production rates exceed the set rate (i.e. tipical ‘open flow’ for a flowline leak at surface), the consequent pressure drop across the valve is such to cause valve closure. Valve with this characteristics are available only as wireline retrievable valves. - Setting depth In this case there are no limitation in setting depth. Agip policy is to require for all new developments Surface Controlled Valves, leaving the use of flow controlled valves only to particular injection applications or as a back up for production wells (see guidelines at the end of the chapter).

7.3

VALVE CLOSURE MECHANISM

From the point of view of the closure mechanism there are two different configuration available (figure 5,6); flapper type or ball type. - Flapper Valves The valve closure mechanism is the flapper which is kept open by the flow tube during its openig travel downwards; the flapper rotates 90 ° around its hinge and locates inside a recess of the body (tubing retrievable valves) or in a cut out section of the bottom sub (wire line 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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retrievable valves). In this position the flapper is protected by erosion due to produced fluids by the flow tube. When the flow tube is moving upward in its closing movement, the rotational spring coiled around the flapper hinge, even with its low force, moves the flapper in the flow and the flow helps in valve closing. According to the different well conditions, the flapper seals against the sealing seat through metal to metal seals or through elastomer seals: even when defined metal to metal seal the sealing element incorporates a ‘non elastomeric’ soft seat which guarantees the sealing at low pressure differential. The possibility of pumping through the valve is easy to achieve, due to the irrelevant force needed to open the flapper once pressure has been balanced across. - Ball Valves The valve closure mechanism is, in this instance, a ball with the central bore which, in open position, grants the nominal full bore size of the valve itself. In opening and closing the valve rotates around its horizontal axis and the rotation is caused by the sliding of a lug mounted on the ball seat inside a slanted slot machined on the ball valve body. When closed this type of sealing can guarantee metal to metal sealing, at least when the valve is new. It is more prone to failure (ref SINTEF report) due to the ball, when open, to scale up and so not respond correctly in its fail safe mode. When in service for long period of time there is also the possibility for the ball, during its opening movement, not to open completely so reducing the full bore ID and also causing possible interference problems with wire line tools. Agip policy considers for all new applications the only use of flapper valve type safety valves (see guidelines at the end of this chapter).

7.4

SAFETY VALVE CONFIGURATION

From this point of view two alteranatives are available: - Tubing Retrievale - Wire line Retrievable - Tubing Retrievable These kind of valves are made up directly on the tubing and maintains tubing ID as big as possible for wireline activity and for localized friction loss reuction (very important in wells with high well scaling tendency or with asphaltene/paraffine deposition).


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Figure 5. Flapper closure mechanism


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Figure 6. Ball closure mechanism There limitation is the big OD required, which is function of size and rating and in many cases, expecially in exixting installations, impair their use even as a retrofit, having to match with existing casing profile. In new installations their use is widely expanding requiring in general terms a production casing profile with a top section enlarged to accomodate for the valve itself. All these valves are normally provided with a lock open feature which in case of failure lock the flapper open to allow for the possible installation of a wireline retrievable safety valve, whose packing straddle the flapper itself maintaining the integrity of the hydraulic control. From an acquisition point of view it must be stressed that all of their parts withstand the foreseen rating and all external threads have the same engineering features (pull, torque, seal capability) of the tubing connections. - Wire line Retrievable Safety Valves They are usually installed in landing nipple profiles which fit the tubing size. They are used in completions which are usually designed for last the whole field life, so that they can be retrieved on a regular basis for redressing and refurbishment, or for completions 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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where the existing combination of production casing and production tubing does not allow for the installation of a tubing retrievable valve. Their major limitation is the ID reduction which, for the reasons explained in the above paragraph, can be detrimental for a positive well management. They are available either in the flapper configuration or in the ball configuartion and incorporates also those configurations which are ‘flow controlled’ (velocity, storm chokes). Their main failure mode is the packing failure, or internal part erosion wear. Agip policy recommends for all new applications the prevalent use of tubing retrievable type safety valves (see guidelines at the end of this chapter).

7.5

EQUALIZATION

All Surface Controlled Downhole Safety Valves require in general the pressure equalization across the closure mechanism, before opening the valve with the control line pressure; this to avoid a couple of phenomena: first, possible flapper/ball wash-out during the equalization process; second, the break of the flapper hinge or of the ball seat lug. Nevertheless all above mentioned valve typologies and configurations, exist in the self equalizing besides the non self equalizing version. Equalization is obtained in at least three different ways: - a. through poppet in the flow tube and labirynt - b. through the flapper - c. through a poppet in the flow tube All of them have advantages and disadvantages, the biggest one, valid in general, is the possibility to have a leak path open whenever the system would fail or wash-out. The best one seems to be the first one since it allows for energy dispersion before the fluid enters the poppet, so avoiding problems of poppet wash-out; on the other end this method of equalization, in case of production of dirty fluids, is more prone to settle deposits. at the end impairing the safety valve functionality. Agip has not yet done any qualification testing of equalizing systems and in its guidelines (see below) does not recommend their utilization in surface onshore/offshore installations. The only case in which Self Equalizing Valves are recommended is in subsea installation and in any case only as a back-up to the common equalization procedure. In this case the recommended one is the a) system.


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ANNULAR SAFETY SYSTEMS

There are special occasions where, besides the needs fore a tubing safety valve, there is the need for annular safety. This is usualy required when conventional gas lift system, with gas injection in the annulus at high pressure (up to 3000 psi), to avoid that the annulus, in case of a well head failure, acts as a reservoir gas feeding a possible fire at surface (also taking into account possible leaks developing at gas lift mandrel level). There can be three possible scenarios: - Annular concentric Safety Valves - Annular vent valves - Twin Safety Valves - Twin safety valves They are clearly installed on the second string and control the annulus in special applications (figure 7). This configuration has been studied to control the annulus injected gas lift stream on a secondary string, to avoid that the gas, containing Carbon Dioxide and Hydrogen Sulphide is in contact with the casing and the mud line tie-back system. To be installed they require the installation of a surface tubing hanger whose main characteristics are to sustain the full tubing string and to anchor inside the production casing which at this depth is usually unsupported (not cemented), without damaging it (burst); for this purpose such type f hangers have special multicone, 360 ° slips. - Annular concentric Safety Valves They consist of a packer shape tool, which interrupt the casing flow path, and of a concentric flow path for the annulus stream inside the packer (figure8). The hydraulic control fluid pushes down either a concentric flow tube or a poppet to clear the seal against a spring, in the same exact way that a tubing mounted valve does. Releaving the hydraulic control pressure will fail safe close the Valve. - Annular Vent Valves They consist usually of a very simple spring loaded hydraulic controlled poppet valve (figure 9) mounted on the third outlet of an Electrical Submersible Pump Dual Packer top sub (first outlet for the flow, second oulet for the cable, thrd outlet for the vented gas). Usually these type of valves, having reduced flow paths, suffers from paraffin deposition if carried by he gas or from corrosion because of liquid (always present in the gas stream) drop out on their top, which in certain conditions can also affect their performance, inducing a back pressure at valve level. For the above reasons these valves, evn if used in environmentally standard conditions usually require a metrial upgrade to be decided case by case.

7.7 7.7.1

REFERENCE STANDARDS STANDARDS

API Specification 14 A and API Recommended Practice 14 B are the baseline standards for Safety Valves. In addition ANSI/ASME SPPE-1 (ANSI = American National Standard Institute; ASME = American Society of Mechanical Engineers; SPPE = Safety and Pollution Prevention Equipment) estabilishes the requirements for quality assurance programmes ad acreditation of manufacturers and refurbishers of offsore safety and pollution prevention equipment. Clearly to maintainthe safety


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valves per SPPE-1 is a very costly project and its applicability shall be evaluated per area of application also bearing in mind local infrastrucure and supplier local facilities.

Safety Valve SL

Safety Valve SC

Figure 7. Twin Safety Valve


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Figure 8. Annular safety system


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Figure 9. Annular Vent Valve In any case purchasing valves per SPPE-1 guarantees that: - All critical components are traceable fromm mill pour to finished product. - All suppliers or subsuppliers of critical components have been qualified - A product is fully qualified, including the independent testing and certification of a prototype - The product is stamped with OCS stamp (OCS = Offshore Continental Shelf) or satisfies the sandy service A valve puchased to API 14A guarantees that: - All critical components are traceable to mill heat reports - Design has been qualified through funcyion test - The product is manufactured, inspected and functionally tested 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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API 14A foresees three different classification of service: - Class 1 - Standard Service Suitable for installation in normal wells - Class 2 - Sandy Service Suitable for installation where sand or silt is going to be expected - Class 3 - Stress Corrosion Cracking Service In addition to class 1 and 2, the valve is suitable for use where corrosive agents are expected: Class 3S for sulphide stress corrosion cracking Class 3C for chloride stress cracking 7.7.2

OPERATIONAL TESTING FREQUENCY

Operational testing is commonly a trade off between different issues (local field management, local regulations, well conditions etc.) and also between the need of insuring that the valve is still operational against the possibility of inducing failures during testing. In general, recommended testing frequency, closing the valve, bleeding well pressure above it to 500 psi and recording any possible build up in tubing and control line pressure for 15 min, is every six months. Acceptable leak rates are defined by API RB 14 B. It is clear that once the failure is detected in case the valve is a tubing retrievable, the possibility of installing a wireline retrievable exists till the first planned workover; in case instead the valve is wireline retrievable, it can be changed out and retested to verify the failure does not nvolve the nipple itself.

7.8 ENGINEERING PROCESS FOR CONTROLLED SUBSERFACE SAFETY VALVE A)

SELECTION

OF

THE

SURFACE

WORKING PRESSURE IS DEFINED AS: A.1.) or A.2.)

W.P. = STATIC BOTTOM HOLE PRESSURE (SBHP) W.P. = MAX STATIC TUBING HEAD PRESSURE x S.F. (STHP x S.F.)

where S.F. = Safety Factor For Gas Wells: S.F. = 1.1. For Oil Wells: S.F. = 1.3. Use SBHP or STHP x S.F. in according with Tab.1 and figure 7 All definitions regard to Enclosure 1 of API 6A Suggested Safety Factor for Oil Wells is only indicative. It’s required to evaluate case by case. The G.O.R. evolution (if there is great gas caps, or wells with possible hydraulic communications to gas wells or oil wells with flowing pressure near to Pb etc). In all these cases, the opportunity to use the SBHP as W.P. has to be considered, looking to the geometric implications involved in (bigger size) this choice.


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REVISION 0 1

TEAP-P-1-R-8796 B)

PAG

TUBING RETRIEVABLE VALVE - INTERNAL SEAL SYSTEMS B.1.) STANDARD SITUATIONS (No H2S, No CO2)

W.P. psi ≤ 5.000 > 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

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.


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7.9

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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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REVISION 0 1

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

START HERE

STATIC BOTTOM HOLE PRESSURE > 10000 PSI

YES


SBHP

YES

NO NO CLOSE PROXIMITY?

SBHP

YES

NO

SBHP > 5.000 PSI

YES NACE?


YES

YES STATIC BOTTOM HOLE PRESSURE

SBHP

CLOSE PROXIMITY? NO

SBHP <=5.000 PSI YES

NO

NO

SBHP

CLOSE PROXIMITY?

NO

STHPxS.F.

YES CLOSE PROXIMITY?

STATIC BOTTOM HOLE PRESSURE

> 5.000 PSI

<= 5.000 PSI

SBHP

STHPxS.F.

NO STATIC BOTTOM HOLE PRESSURE

> 5.000 PSI

STHPxS.F.

> 5.000 PSI <= 5.000 PSI STATIC BOTTOM HOLE PRESSURE

CLOSE PROXIMITY?

STHPxS.F.

YES SBHP

NO <= 5.000 PSI

STHPxS.F. STHPxS.F.


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TYPE OF ACTIVITY'

ISSUING DEPT.

DOC. TYPE

REF. N.

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8797


Volume 1 CHAPTER 8 - PRFORATING -






€ Issued by REVISIONS

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

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


PREP'D

CHK'D

APPR'D


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INDEX 8.1 INTRODUCTION .......................................................................................................................3 8.2 GUN SYSTEMS.........................................................................................................................4 8.2.1 SHAPED CHARGES........................................................................................................4 8.2.2 8.2.2 DETONATORS ......................................................................................................6 8.2.3 PREVIOUS API TESTS (FOURTH EDITION) ..................................................................7 8.2.4 NEW API TESTS (FIFTH EDITION).................................................................................8 8.2.5 GUN SCALLOP..............................................................................................................10 8.2.6 CLEARANCE .................................................................................................................11 8.2.7 CASING .........................................................................................................................13 8.2.8 PHASING AND SPACING..............................................................................................15 8.3 COMPLETION TECHNIQUES ........................................................................................................16 8.3.1 PERFORATED CASING COMPLETION........................................................................16 8.3.2 FACTORS AFFECTING PRODUCTIVITY......................................................................16 8.3.3 FORMATION STRENGTH AND STRESS CONDITIONS...............................................21 8.3.4 UNDERBALANCE..........................................................................................................21 8.4 8.4 ...........................................................................................................................................22 8.4 PERFORATING TECHNIQUES .......................................................................................................23 8.4.1 THROUGH-TUBING PERFORATING ............................................................................23 8.4.2 CASING AND HIGH SHOT DENSITY GUN PERFORATING.........................................23 8.4.3 WIRELINE- AND TUBING-CONVEYED PERFORATING ..............................................23 8.5 SAFETY AND OPERATING ENVIRONMENT .....................................................................................24 8.5.1 SAFETY .........................................................................................................................24 8.5.2 TRANSPORTATION ......................................................................................................24 8.5.3 WELLSITE .....................................................................................................................24 8.5.4 STRAY VOLTAGE SAFETY ..........................................................................................25 8.5.5 HIGH TEMPERATURE AND PRESSURE .....................................................................26 8.5.6 FLUID CHEMICAL PROPERTIES..................................................................................28 8.5.7 MUD WEIGHT................................................................................................................29 8.5.8 WELL DEVIATION .........................................................................................................29 8.6 WIRELINE THROUGH-TUBING GUNS...................................................................................31 8.6.1 GUN SELECTION ..........................................................................................................32 8.6.2 SPECIAL PRECAUTIONS .............................................................................................34 8.7 WIRELINE CASING GUNS ...........................................................................................................34 8.7.1 GUNS SELECTION........................................................................................................34 8.8 OPERATIVE PERFORATING TECHNIQUES ....................................................................................34 8.8.1 WIRELINE PERFORATING TECHNIQUES ...................................................................35 8.8.2 TCP (TUBING-CONVEYED PERFORATING) TECHNIQUES .......................................36


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8.1

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INTRODUCTION

The well can be completed in two way: open hole cased hole In the first one the last drilled part of well remain not lined by the casing and the oil and/or the gas flow straight to the formation to the wellbore. In the second option, most largely diffused, the reservoir and the wellbore should be put in communication. The shaped-charge perforating is the most common method for achieving communication between formation and the wellbore. The character of this communication path through the cement and the casing is critical to the completion and to well performance. It should allow well max. productivity by creating clear channel through the portion of the formation damaged during drilling process, by providing uniform entry points through the casing and cement for possible hydraulic fracturing fluids and proppants, and by making many large uniform hole for sand control when required and hydrocarbon production.


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8.2

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GUN SYSTEMS

Explosives were invented first by the Chinese in the 10th century, then independently by the Arabs in the 13th century. The low explosive, or black powder, was characterised by slow reaction rates, 500 to 1500 meters per second (m/sec), and relatively low combustion pressure. Much later, in 1846, the first high explosive was discovered by an Italian, Ascanio Sobreto, and then made commercially by Alfred Nobel in 1867 with the development of dynamite, a combination of nitroglycerine and clayey earth. High explosives, unlike the earlier low explosives, detonate at very rapid rates of 5000 to 9000 m/sec and generate tremendous combustion pressures. The terms low and high explosive are still used to characterise chemical explosives. Low explosives (propellants) are used in modern oilfield applications as power charges for pressure setting assemblies, bullet perforators and sample-taker guns as well as for stimulation (high-energy gas fracturing, perf wash, etc.). High explosives are found in shaped charges, detonating cord and detonators or blasting caps. High explosives are further classified by their sensitivity or ease of detonation. Primary high explosives are very sensitive and easily detonated by shock, friction or heat. For safety reasons, primary high explosives, such as lead azide, are used only in electrical or percussion detonators in gun systems. Secondary high explosives are less sensitive and require a high energy shock wave to initiate detonation (usually provided by a primary high explosive). Secondary high explosives are used in all other elements of the ballistic chain (detonating cord, boosters and shaped charges). PETN, RDX, HMX, HNS and PYX are secondary high explosives used in oilwell perforating. The rate of reaction, combustion pressure and sensitivity of chemical explosives are affected by temperature. Consequently, maximum safe operating temperatures are defined for all explosives. Exceeding temperature ratings may result in autodetonation or reduced performance. Listed in the table below are the one-hour and one-hundred hour temperature ratings and uses for the various explosives in gun systems (rif. Fig 7.9).

8.2.1

SHAPED CHARGES

In 1888, C. E. Munroe observed that explosive cotton indented with the letters USN (US Navy) left impressions when detonated next to steel plates. Further experimentation with different indentations or cavities yielded penetrations of one-half the cavity diameter. Munroe's cavity effect did not seem significant until the late 1930s when a Swiss, H. Mohaupt, discovered that enormous penetrations in steel occurred when an explosive cavity was lined with metal. This discovery formed the foundation of modern shaped-charge theory. The shaped charge was first developed and used in World War II antitank weapons, including the bazooka. After the war, in 1948, shaped-charge technology was extended to its first commercial application, oilwell perforating. Since then many advances in shaped-charge design have been made through the use of computer simulations and high speed photography. The basic shapedcharge concept, however, has remained the same. A shaped charge consists of four components: the outer case, main explosive charge, primer charge and the metallic liner. The outer case is a containment vessel designed to hold the detonation force of the charge long enough for the shaped-charge jet to form. This containment is also critical to preventing interference 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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with adjacent charges in the gun system. Steel, zinc and aluminium are the most common case materials; however, ceramics and glass are also used. Regardless of the material used, tight design and manufacturing tolerances are necessary to ensure correct perforator performance. The main explosive charge is normally chosen based on the desired temperature rating of the shaped charge. Of equal importance is the ability of the explosive to be mechanically pressed into a conical form typical of a shaped charge. The more homogeneous and uniformly distributed the explosive mixture, the better the jet formation and the deeper the penetration. The main explosive charge is normally chosen based on the desired temperature rating of the shaped charge. Of equal importance is the ability of the explosive to be mechanically pressed into a conical form typical of a shaped charge. The more homogeneous and uniformly distributed the explosive mixture, the better the jet formation and the deeper the penetration. The primer provides the link between the detonating cord and the explosive charge. It is usually composed of the same explosive material as the main charge but has greater sensitivity. At the centre of the shaped charge is the liner. The collapse of the liner under the detonation force of the main charge is the critical action in the formation of the perforating jet. Initially, liners were constructed of solid metal. These designs successfully produced high-density jets but tended to plug perforation tunnels with debris, called a slug. Modern liner designs are based on mixtures of powdered metals that give the jet sufficient density for deep penetration without the undesirable side effect of formation plugging. Powdered metal liners have replaced the solid liner in all charges except those designed for maximum entrance hole diameter, the big hole (BH) charge. These charges are used for sand control applications. In the big hole charge, penetration depth is less important than entrance hole size. Therefore, solid liners are used because they tend to produce very large holes through the casing and cement. The undesirable effect of the slug is negated by the large hole sizes and high permeability of the formations in which these charges are typically shot. Copper is the most common solid liner material. Common powdered metal liner materials are copper, tungsten, tin, zinc and lead. These powdered materials are blended together to provide a jet of uniform density and velocity gradient. This uniformity of density and velocity is critical to providing and maintaining consistent jet performance. Once the shaped charge has been placed in a gun and the gun positioned in a well, the detonation begins at time To with the initiation of a detonator. This initiates an explosive wavefront travelling down the detonating cord at about 7000 m/sec with pressures around 15 to 20 gigapascals (GPa). The detonating cord in close contact with the primer region of the shaped charge detonates the primer, which initiates the main explosive charge. The charge detonation increases in speed and advances spherically until it reaches terminal speed of about 8000 m/sec and pressures of 30 GPa. This occurs just prior to the arrival of the wavefront at the apex of the liner. At this point the case expands radially about the symmetry axis of the charge while the liner is thrust inward. At the point of impact on the axis near the apex of the liner, the pressures increase to more than 100 GPa. From this point the liner parts into two axial streams, a faster, forward-moving stream forming the tip of the jet and a slow, forward-moving stream forming the tail. The jet tip travels at around 7000 m/sec while the tail travels at about 500 m/sec forming a velocity gradient responsible for the stretching of the jet required to achieve casing and formation penetration. To better understand the penetration process, the jet may be thought of as a high velocity, rapidly expanding sacrificial rod with impact pressure of 100 GPa. As the jet impacts the casing, the enormous pressure causes the casing material to flow plastically away from the jet. As the jet passes through the casing, the cement and formation flow away in the same manner while eroding 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 tip of the jet until all the energy is expended at the end of the perforation tunnel. Penetration is achieved by the high pressure associated with the jet of powdered or solid metal pieces (depending on the liner type) pushing aside the various materials rather than by a burning, drilling or abrasion process. Consequently, the quality of a shaped-charge perforator depends upon achieving a long, consistent jet with the optimum velocity gradient.

Case

Primer Conical liner

Min explosive Elements of a shaped charge 8.2.2

8.2.2

DETONATORS

Two types of detonators are generally used to initiate the ballistic detonation of a perforating gun: electrical detonators or blasting caps, and percussion detonators. Electrical detonators are used in electrically fired guns in wireline applications. These are also a vital safety link in the system. The three components of typical fluid-desensitised electrical detonators are the ignition section, the air gap and the booster section. The ignition section is energised by passing current through two safety resistors causing a filament to heat and the match compound to burn. This burning detonates the primer charge, lead azide, which in turn detonates the booster section across an air gap. Critical to overall safe operation are the two safety resistors, since they increase the resistance of the detonator to stray currents. The air gap prevents detonation of a flooded gun string by allowing fluid entry via the fluid entry holes; this effectively prevents initiation of the booster section. This safety feature precludes the type of catastrophic damage encountered with the detonation of a wet gun. With exposed guns the detonator is pressure sealed and is not fluid-desensitised. The booster section is the last link in the cap detonating the detonating cord. The explosive material in the booster section is chosen for the appropriate temperature rating of the detonator. The detonator temperature rating and pressure rating used with exposed guns are critical and must never be exceeded or autodetonation may occur. Percussion detonators are used in TCP systems. They are mechanically fired by the action of a firing pin impacting a pressure-sealed membrane that covers an abrasive grit and lead azide primer


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charge. The action of the penetrating firing pin generates a force that detonates the primer charge. which in turn detonates the booster section. A new type of perforating gun initiation system is now available to replace the resistored electrical detonator for wireline perforating applications. The S.A.F.E. Slapper-Actuated Firing Equipment initiates a gun firing without the use of any primary detonating material. The initiation system is built around Exploding Foil Initiator technology and uses a high-energy, short-duration electrical pulse to initiate the explosives. Adapted to almost all Schlumberger gun systems, S.A.F.E. equipment allows concurrent operations, welding, helicopters, radio transmission and cathodic protection systems to remain active during perforating operations.

8.2.3

PREVIOUS API TESTS (FOURTH EDITION)

The Fourth Edition API requirement in Section 1 defines a concrete target for the evaluation of bullet and jet perforators under multiple-shot, surface conditions.

casing

gun

Test specimen

water

steel form

28-day concrete

API Section 1 concrete target The physical characteristics of the perforation at different clearances, including penetration into concrete, entrance hole diameter in J-55 grade casing and burr height, are evaluated. The Section 2 test is designed to determine the physical characteristics of the perforation in a reservoir-like rock core and to evaluate the flow efficiency of the perforation. For each of three tests, a single-shot section of the perforating gun is used, opposite a Berea sandstone core inside a test chamber. After gun firing, fluid is flowed through the core, and core permeabilities are compared (before and after) to yield a core flow efficiency (CFE).


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API Section 1 and 2 tests are routinely performed on deep penetrating charges. Only Section 1 tests are performed on big hole charges. Shaped charges exceeding 35 g of explosive are exempt from the Section 2 test because of the potential for damage to laboratory apparatus.

8.2.4

NEW API TESTS (FIFTH EDITION)

The American Petroleum Institute has revised its requirements for charge certification with the Fifth Edition. New targets and procedures are required for official certification by July 1, 1992. Sections 1 and 2 are required for perforator certification. Sections 3 and 4 are optional and intended for perforator systems verification.

8.2.4.1

SECTION I GUN SYSTEM TEST

The new Section 1 API target is similar to the existing API Section 1 concrete target. The test is performed at surface temperature and pressure, measuring and recording total penetration depth, casing entrance hole and burr height. The gun is shot eccentered to provide entrance hole variations versus the gun-to-casing clearance data. Enough charges are tested to provide a complete description of the effect over 360°.

8.2.4.2

SECTION 2 STRESSED BEREA TARGET TEST

The purpose of the new Section 2 is to provide a standard test for measuring perforator performance in stressed Berea sandstone with simulated wellbore pressure applied. Charges marketed for gravel-pack applications are specifically excluded, as are charges containing over 600 grains [38.9 g] of explosives. For deep penetrating charges 15 g or less, a 4-in. diameter core is cut from a block of Berea sandstone. For charges exceeding 15 g, a 7-in. diameter core is cut. After the core is dried, it is vacuum-saturated with a 3% brine. Then, the target and a single-shot perforating gun section are placed in a pressure vessel and 3000-psi effective stress is applied. The gun section is fired at ambient temperature. A minimum of three single shots into three targets are made. Penetration and hole size (entrance hole into the mild steel face plate) are measured and averaged.

8.2.4.3

SECTION 3 ELEVATED TEMPERATURE AND PRESSURE TEST (OPTIONAL)

The purpose of this optional test is to evaluate perforating systems at elevated temperature and atmospheric pressure and to test the hardware at elevated pressure. The charges are loaded into a gun with laminated steel targets mounted around it. The entire system, including the firing head and associated hardware, is heated to and kept at rated temperature for a specified time, then fired at temperature. The performance is compared to that at room temperature with similar targets to evaluate charge and transfer reliability. For TCP systems, at least one detonation transfer must be demonstrated. A separate pressure test is made at rated pressure, temperature and time to verify the operational rating of the system hardware. No explosives are required for this test.


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REVISION 0 1

TEAP-P-1-R-8797 8.2.4.4

PAG

SECTION 4 FLOW PERFORMANCE TESTS (OPTIONAL)

These optional tests measure the flow performance of a perforation and are similar to the Section 2 test of the 4th Edition. The general procedure may be used on quarry rock or well core under conditions that simulate site-specific downhole conditions. A set of standard test conditions is also provided. Tests are performed in a confinement pressure vessel containing a cylindrical core provided with: - a face plate simulating well casing - a flexible jacket to transmit simulated overburden stress to the sample - provisions for applying pore fluid pressure to the boundaries of the sample (the flow system)

wellbore pressure in

simulated overburden pressure in

pore pressure in

gas-charged accumulator

3-micron filter simulated wellbore

perforating gun

target

simulated overburden

API RP-43 Section 4 test configuration Pore fluid pressure may be applied to the cylindrical sides of the sample (radial flow), to the unperforated end of the sample (axial flow), or both, in a manner simulating in-situ pore pressure fields. The single-shot gun section is contained in a second pressure vessel simulating the wellbore. The perforation geometry is described as the debris-free penetration depth the total core penetration to the deepest effect of penetration, and the perforation diameter profile at 1-in. intervals. From the flow rate data and the perforation and core characteristics, a core flow efficiency is determined. The performance of a perforator in downhole environments is critical to the success of the well completion. Although the API has devised tests to provide a comparative basis for the performance of a perforator at surface conditions, as yet no complete analytical criteria exist to translate this performance to the in-situ conditions of the wellbore. There are, however, data that suggest trends and certain expected results. The next section discusses the effects of gun scallop, clearance and casing. 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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8.2.5

GUN SCALLOP

8.2.5.1

EFFECT ON PENETRATION

0 1

In a deep penetrating charge, most of the penetrating ability of the jet comes from the tail, representing the last 30% of the liner. Therefore, the additional amount of steel close to the gun, such as extra gun thickness, has only a small effect on the final penetration depth. Tests indicate about a 5% reduction in penetration. However, scallops provide a recess for the burr in cases where burrs would interfere with the minimum restriction of the completion, or scratch the casing surface.

8.2.5.2

EFFECT ON THE ENTRANCE HOLE

Most of the jet and liner for a big hole charge is used to penetrate the gun, water and casing. This portion of the jet is generally more affected by the amount of steel that must be penetrated. Smaller hole sizes in the casing result, and this becomes an important factor in the design of big hole charges where the desired result is a large casing entrance hole.

8.2.5.3

RELATIONSHIP BETWEEN HOLES IN GUN, CASING AND CEMENT

The diameter of the hole made by the jet depends on the strength of the material. The hole size in the gun is generally not representative of the hole size produced in the casing, cement or formation. For retrievable, nonreusable gun families, the hole in the gun is usually smaller than the hole in the casing. In the case of the big hole charge, a smaller hole in the gun wall is produced because these charges are designed to minimise the energy wasted in producing a hole in the gun wall in order to optimise casing hole size. Tests in composite targets (Fig. 7.1) show that the hole in the cement is usually larger than the hole in the casing over most of the penetration depth. While this is true for deep penetrations, it is not necessarily the case with big hole charges. Depending on the amount of the jet "used up" in producing a large hole in the casing, the remaining jet portion may produce a smaller hole through the cement before reaching the formation.


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REVISION TEAP-P-1-R-8797 CASING WALL

GUN

PAG

CEMENT

0 1 FORMATION

WATER

Figure 7.1 8.2.6

CLEARANCE

Clearance can be characterised in two ways, "in-gun clearance, or stand-off," and "gun-to-casing" clearance. Stand-off is usually designed to allow adequate space for the collapse of the liner and jet formation prior to the liner hitting the gun interior wall. The gun-to-casing clearance usually does not have a significant effect on the amount of penetration until the clearance exceeds approximately 30% of the gun diameter. Figure 7.2 shows qualitatively the effects of clearance on penetration.

Penetration

D eep Penetration

B ig h o l e

C learance


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Although clearance has a relatively small effect on the penetration of a big hole charge, it has a large effect on the hole size. This can affect the total area open to flow as well as the perforation tunnel volume. These factors can be optimised by using the Ultrapack* family of big hole shaped charges in conjunction with a gun positioning device. Optimum charge performance is obtained when the gun is shot in the centre of the wellbore. At this position, the entrance hole is largest, the total area open to flow is greatest, and the holes have consistent diameters. If a positioning device is not used, it is possible to have a situation in which the gun is shot at minimum clearance (gun touching the casing) or maximum clearance (cross-casing shot). Thus, without gun positioning, entrance hole sizes may range anywhere depending on the random location of the gun in the wellbore.


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8.2.7

CASING

8.2.7.1

EFFECT OF MULTIPLE CASING STRINGS

0 1

Multiple casing strings greatly affect the entrance hole of big hole charges. These charges are designed to produce a large hole in only one casing. The reduction is two to three times the cumulative wall thickness. To estimate entrance holes in multiple casing strings, a surface mock-up of the installation is prepared and test shots fired. An estimation of the entrance holes in multiple casings (if present) can be obtained as follows: The entrance hole in the second casing will be 90% of the entrance hole in the first casing when the gun is at maximum clearance. This maximum clearance data can be obtained from new API Section 1 certification tests. The entrance hole in the third casing will be at least 10% smaller than the entrance hole in the second casing. Typically, a 22-g Ultrajet* charge makes a 0.35-in. hole in the second casing; a 32-g charge makes a 0.45-in. hole; and a 60-g charge makes a 0.6-in. hole.

8.2.7.2

EFFECT OF CASING STRENGTH ON ENTRANCE HOLE

The diameter of the perforation entrance hole in casing is affected by a number of factors, particularly casing strength and thickness. Standard hydrodynamic penetration theories predict that the entrance hole is reduced as the casing hardness increases. The hole size is related to the ultimate tensile strength (hardness) of the casing. The formula for this correction is Dp = (Dp(J-55))[2980.8/(2250+4.2 x)]1/2 Since Brinel hardness (x) is not a common field unit, Table 7.1 is provided to show the equivalence between casing grade, minimum yield, tensile strength, and Rockwell and Brinell hardness. CSG H-40 J-55 K-55 C-75 L-80 N-80 C-95 S-95 P-105 P-110 Y-150

ROCKWELL “B” 68-87 81-95 93-102 93-103 93-100 95-102 96-102

ROCKWELL “C”

14-25 14-26 14-23 16-25 18-25 22-31 25-32 27-35 36-43

BRINEL 114-171 152-209 203-256 203-261 203-243 209-254 219-254 238-294 254-303 265-327 327-400

Yp min (kpsi) 40 55 55 75 80 80 95 95 105 110 150

Ts (kpsi) 60-84 75-98 95-117 95-121 95-112 98-117 103-117 109-139 117-143 124-154 159-202

Table 7.1


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EFFECT OF CASING THICKNESS

All charges generally produce uniform diameter holes in the standard API RP-43 4th Edition casing. When the casing thickness increases by more than about 25% beyond J-55 casing thickness, the exit hole from the casing becomes smaller than the entrance hole. 8.2.7.4

EFFECT OF ENTRANCE HOLE AND SHOT DENSITY ON CASING STRENGTH

The holes made by perforating the casing wall reduce the casings ability to withstand collapse. The remaining collapse strength of casing after perforating is determined by several factors including: - initial casing strength - diameter of perforation entrance hole in the casing wall - number of perforations - vertical distance between adjacent perforations (determined by a combination of shot density and the phasing pattern of the gun) - the change in the strength of the casing material in the region immediately surrounding the perforation. (The mechanical properties are altered by the process of the shaped-charge jet passing through the casing wall.) - the support integrity of the formation and cement sheath surrounding the casing. Figure 7.2 illustrates the effect on post-perforation remaining casing strength as a function of casing entrance hole diameter and perforation phasing/shot density. This figure does not include effects from the increase in mechanical properties of the casing in the region immediately surrounding the entrance holes nor the supporting effect provided by the formation and cement sheath. The location of the data points on the graph corresponds to actual entrance hole diameters from gun systems with the indicated shot density and phasing. Note that the 135°/45° phasing pattern provides the most remaining casing strength of the 12 SPF guns shown. E ffect of EH and Phasing on Remaining Casing Strength A

Remaining casing strength

1 0.90

B

0.80 C

D

0.70

A B C D

0

0.25

0.5

0.75

1

= = = =

5 SPF 60° 12 SPF 135°/45° 12 SPF 120°/60° 12 SPF 120°

1.25

E n trance hole size (in)

Figure 7.2 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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PHASING AND SPACING

The Schlumberger 41/2- and 7-in. HSD guns contain a unique 135/45° charge phasing pattern. Compared with other phasings of guns the same size, this pattern maximises well productivity and gravel-pack efficiency. The 7-in. 140/20° phased 14 shots per foot HSD gun system is a further enhancement for high-density perforating. The shot-to-shot spacing progresses at 135° (or 140°) radially and 1 in. (or 0.86 in.) vertically to provide an effective 45° (or 20°) phasing between vertical columns of perforations and one shot per plane horizontally. The one shot per plane horizontal spacing is well-suited for laminated and shaley sands to maximise the probability of hitting producible layers. The high number (eight or eighteen) of vertical columns in combination with the one shot per plane horizontal spacing are highly effective for intersecting fractures. The combined or resulting phasing pattern of the production perforation tunnels in the formation maximises the drainage efficiency of a reservoir.

12 SPF

0°

180°

360°

Example of a 135° phasing with 12 shots per feet (the charges are spaced 45° apart)


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Completion Techniques

8.3.1

PERFORATED CASING COMPLETION

In a perforated casing completion, a gun is positioned across from the producing formation and detonated; this creates perforations to the formation through the casing and cement. Perforating may be accomplished with or without well completion tubulars and bottomhole assembly in place in an overbalanced or underbalanced pressure situation. Choosing the right perforator for a completion is a process based upon optimisation of various factors-geometrical, reservoir and perforating environments (completion fluid, fluid level and underbalance) that affect productivity.

8.3.2

FACTORS AFFECTING PRODUCTIVITY

8.3.2.1

GEOMETRICAL FACTORS

The major geometrical parameters that determine the efficiency of flow in a perforated completion are shot density (perforations per foot), perforation penetration in the formation, angular phasing and perforation diameter. Other geometrical factors that may be important in special cases are partial penetration, well deviation, formation dip and drainage radius. The impact of these factors on well productivity depends on the type of completion, formation characteristics and formation damage. Table 7.2 indicates the relative importance of the four main geometrical parameters based on the completion type (1 is more important, 4 is least).

Table 7.2: Perforating main parameters relative importance

Geometrical parameter Effective shot density Perforation diameter Perforation phasing Perforation length

8.3.2.2

Completion Type Sand control Natural unconsolidated consolidated 2 1 or 2

Stimulated consolidated 2

Remedial damage 2

1

3 or 4

3

4

3

3 or 4

2

3

4

1 or 2

4

1

FORMATION CHARACTERISTICS

The productivity of a perforated completion is affected by characteristics of the target formation in two ways. The performance of a perforating charge/gun system, under downhole conditions, is significantly different from the surface test performance because of in-situ formation stress conditions, formation


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strength and heterogeneities. Thus, the actual values of the geometrical parameters differ from the surface test data. The flow geometry is determined by a combination of the formation characteristics and perforation geometry. Such formation characteristics as anisotropy, laminations and natural fractures significantly alter flow geometry and flow efficiency.

8.3.2.3

FORMATION DAMAGE

Invasion of the mud and cement filtrates into the formation during drilling creates a zone of lower effective permeability around the wellbore. Similarly, during the perforating process, a "crushed zone" of reduced permeability is created around the perforation. The damage caused by drilling and the "crushed zone" may significantly affect the flow efficiency of a perforated completion. Figure 7.3 graphs the effect of a damaged zone surrounding the wellbore on the productivity of a perforated completion. Significant reduction in productivity occurs if the perforations do not extend beyond the damaged zone. Even for perforations that do penetrate farther, the damaged zone reduces the effective penetration length. For formations with significant damage , the perforation length should be greater then the damage width

Open hole 1.0 No crushed zone Productivity ratio

0.9 0.8 0.7 0.6 0.5

Perforation length

0

3

6

9

12

15

Damaged zone thickness (in.) Figure 7.3


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8.3.2.4 FORMATION FRACTURES)

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(ANISOTROPY,

LAMINATIONS

AND

Effective design and evaluation of the perforation program include consideration of various common heterogeneities in the formation. This information is available from cores, well tests and openhole logs. Figure 7.4 demonstrates the three common types of heterogeneities.

Kz

e

Ky Kx

fractures

anisotrophy

perforations orthogonal network of fractures

shale lamination

natural fractures Figure 7.4 Anisotropy: Most reservoir rocks have a lower vertical permeability than horizontal permeability and are thus anisotropic. Figure 7.5 shows the effect of anisotropy on the productivity ratio.


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6 SPF 120° phasing 0.4 in perf. diam. 8.625 in wellbore diam. 40 acre spacing

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Perforation length (in.) Figure 7.5 The productivity is dramatically affected by the presence of permeability anisotropy. Since the reduction in productivity is much smaller for high shot densities, increasing the shot density is an effective way of overcoming the adverse effects of anisotropy. Shale laminations: Virtually every sandstone reservoir contains significant amounts of shale. The presence of shale influences the transport properties of the system and is a consideration in designing perforated completions. Natural fractures: Many reservoirs have one or more sets of natural fractures that provide high effective permeability even when the matrix permeability is low. The productivity of perforated completions in these systems depends on the hydraulic communication between the perforations and the fracture network, and varies with the type, orientation and interval of natural fractures. Perforation parameters have variable significances in different fracture systems. Figure 7.6 shows the importance of fracture block size (fracture interval) in determining productivity.


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1.6 12 SPF

Productivity ratio

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e = 4 in. 2 SPF

1.2 Open hole

12 SPF

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8 SPF 2 SPF

0.8 e = 40in.

0.6 0.4 0

3

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12

15

Perforation length (in.) Figure 7.6 Figure 7.7 illustrates that for small fracture blocks, perforated completions perform better than openhole (barefoot) completions, particularly when penetration length “L” is increased. The fracture block spacing e is defined in Fig. 7.4.

1.6

Productivity ratio

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1.2 4S

SP

F

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L = 15 in.

0.8

12 SPF L = 3 in.

0.6

4 SPF

0.4 0

10

20

30

40

Fracture interval, e (in.) Figure 7.7


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FORMATION STRENGTH AND STRESS CONDITIONS

Perforation penetration is influenced by formation compressive strength and overburden stress. Penetration decreases with increased overburden stress and formation strength, and is dependent on charge design. American Petroleum Institute Recommended Practices (API RP-43) define the procedures to evaluate the performance of perforating gun systems under surface conditions in a concrete target. Therefore, to estimate penetration performance under in-situ reservoir conditions, it is necessary to transform API concrete penetration data to rock penetration of a given strength under a given stress. Since rock penetration data do not exist for all charges in rock of various strengths, a semiempirical approach is used that combines experimental data with penetration theory. Service Companies have elaborated theories to take into account stress conditions and formation strength and insert it into the “software” they usually provide for charges performance predictions

8.3.4

UNDERBALANCE

The level of differential pressure is important in creating open, undamaged perforations and, therefore, influencing the productivity of perforated completions. The amount of underbalance needed to obtain better productivity and, at the same time, avoid mechanical failure of the formation is critical to the success of perforating operations. Past field experience is the best guide for selecting the optimum underbalance. Three idealised situations that exist within a perforation tunnel are: overbalanced perforating before flowing, overbalanced perforating after flowing and underbalanced perforating. Without cleanup, the perforation tunnel is plugged by crushed rock material and charge debris. In the second case, most of the charge debris has been removed after flowing, but some of the low-permeability zone damaged by the jet remains. In the last case the damage has been removed at the time the perforation was made because of sufficient underbalance. King's charts (1985) with updates (Tariq, 1990) are published empirical charts based on a field study of wells perforated with TCP in sandstone formations. The underbalance was considered sufficient wherever the subsequent acidizing did not improve the well performance. These charts show the correlation between the underbalance pressure used in perforating, the formation permeability and the type of reservoir fluid. Note that there is no difference between oil and gas reservoirs. Some authors suggest that the underbalance selected should be sufficient to overcome the capillary forces for the removal of invaded mud filtrate. The local capillary pressure can be determined using core analysis. It can also be calculated assuming capillary pressure as a function of the height above the free-water level and the difference in fluid densities: Pc =( ρw—ρhe)hg where Pc pw phe h g

= capillary pressure = water density = fluid density = height above fracture = gravity

The underbalance should be approximately twice the capillary pressure since it has to act at a distance in the reservoir. This approach addresses the cleanup of the formation damage by drilling/ 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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completion fluids, but it does not consider the cleanup of a perforation through flushing of loose debris and removal of the crushed zone around the perforations. A series of recently conducted experiments and calculations done by Service Companies gives new insight into the phenomenon of perforation cleanup. The cleanup after underbalanced perforating occurs in two stages: first through high transient fluid pressure gradients and, second, by steadystate pressure gradients across the zone of reduced permeability. The former lasts only a short period of time and involves limited flow volumes, while the latter occurs over an extended period of flow. The concept of transient cleanup may be viewed as requiring a minimum Reynolds number that results in sufficient drag force to remove the permeability-reducing fines from the formation pores. For sufficiently high underbalance (800 to 1000 psi), the initial surge is enough to effectively clean the damage, and little, if any, cleanup occurs during post-shot flow. At lower values of underbalance (200 to 600 psi) for 200 md-sandstone, the postshot flow does remove some damage, yet a significant amount of damage remains in place and cannot be cleaned even at subsequent high differential pressures. From the standpoint of productivity, the goal is to achieve the highest value of underbalance. However, for a number of reasons, the drawdown imposed on the formation should be limited. The drawdown should not cause mechanical failure of the formation. Excessive drawdown may lead to mechanical deformation of the casing and may cause permeability damage in the near wellbore region because of movement of fines. Initial spurt rates under high drawdown may be so high as to reach critical velocity through the completion; that is, the drawdown is limited by the area open to flow. Imposing higher values of drawdown than those needed to reach critical flow accomplishes little beyond endangering the completion mechanically. The critical flow rate can be calculated easily if the smallest area open to flow is known. The formula is given by, Qliquid = PR A / (471 . R0.5) where: Q R PR A

= critical flow rate (B/D), = gas/liquid ratio (mcf/bbl), = reservoir pressure (psig), and = area open to flow (in2)

The initial spurt rate can be calculated with a constant drawdown approach using an apposite graph. Service Companies have a number of tools to aid in the prediction, modelling and evaluation of completions and well tests. They usually calculate perforation performance and analyse productivity results taking in account log data, production logging and well test data. Information are available from Service Companies engineering departments.

8.4

8.4


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Perforating techniques Two basic perforating techniques are available to the completion design engineer. - Through-tubing perforating-the guns are lowered into the well through the production string. These guns may be conveyed with wireline or coiled tubing. - Casing gun or high shot density perforating-large diameter guns are lowered into a cased well before the production string is run. The guns may be conveyed with wireline or the tubing string.

8.4.1

THROUGH-TUBING PERFORATING

-The wellhead and completion string are in place and tested before the casing is perforated. -The underbalance differential from the reservoir into the wellbore provides perforation cleanup. -Perforations may be made as required over the life of the well, with or without a rig on site. -Operating times are low, providing good job efficiency and use of rig time. Maximum perforated interval per run is limited by the surface set-up lubricator and is typically 30 feet.

8.4.2

CASING AND HIGH SHOT DENSITY GUN PERFORATING

-Gun size is limited only by the casing inside diameter allowing the highest performance deep penetrating or big hole charges to be used at optimal shot density and perforating pattern. -When guns are conveyed on wireline, the overbalanced differential from the wellbore into the formation allows the use of longer guns than with through-tubing perforating. Typically 60 feet [ 18 m] can be readily achieved. Only simple wellhead control equipment is needed. -Compared to expendable through-tubing guns, carrier-type guns significantly reduce the amount of perforating debris introduced into the wellbore during the perforating process.

8.4.3

WIRELINE- AND TUBING-CONVEYED PERFORATING

Perforating guns are conveyed into the well on either electric line (wireline) or tubing (production tubing or drillpipe). The choice between wireline and tubing-conveyed perforating should be made based on the completion objectives and operational considerations. From the operational viewpoint, wireline perforating operations are usually faster when there are a few short intervals to perforate. TCP operations are more efficient for long, multiple zone perforation intervals. Because of the higher operating speeds of wireline perforating, explosives are exposed to high downhole temperatures for a shorter time than with TCP. This is an important consideration in hightemperature wells. Tubing-conveyed perforating has a number of benefits: -TCP combines the advantages of the through-tubing gun systems with those of casing gun and HSD systems. -Large guns may be fired in an underbalanced condition with the full well-control equipment and production string in place. -Long intervals may be efficiently perforated in one run with a kill string in place if required. -The programmed underbalance is applied to all intervals perforated, evenly and in a controlled fashion. -A variety of firing systems and accessories accommodates a wide range of well conditions and completion techniques. -After firing, expended guns may be dropped to the bottom of the well allowing future throughThe 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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tubing operations 8.5

Safety and operating environment

8.5.1

SAFETY

Safe operating practices are critical to the long-term success of any activity, especially when the results may be as devastating as the surface detonation of a perforating gun. Service Companies safety commitment should include strict operating rules, properly designed and built equipment and well-trained, highly qualified personnel. While this commitment extends to all activities, only the aspects dealing with the transportation and use of explosives at the wellsite are considered in the following sections.

8.5.2

TRANSPORTATION

The transportation of explosives to and from the wellsite is an integral part of the design and use of a perforating system. In most cases, loaded guns may be transported to the wellsite, but they must never be transported armed (with a detonator attached). All guns should have a positive pressure release in the event of fire. Failure to provide this release could result in an explosion of the perforating gun because of pressure build-up in the gun as it heats. Detonators and detonating cord remnants are always transported separately in approved containers with key-controlled security locks.

8.5.3

WELLSITE


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Figure 7.8 shows Schlumberger example of their “Explosive Safety Handling Procedure”. EXPLOSIVES Field Safety Procedures Schlumberger 1. Hold consultation with client if possible. 2. Check well area for hazards and correct when necessary 3. Hold spot safety meeting. 4. No smoking except in designated areas. Smoking materials must be stored when leaving these areas. 5. Rig up cable. Remove rig wiring that might contact cable. 6. Outside preparations before attaching an explosive device:

7. Instrument cab preparations for explosive operations: a. Disconnect the survey AK piug. b. Turn off all USP and PSP switches and power down CSU. c. Turn off main circuit breakers. d. Turn off AC generators. (On units with generator driven by main engine, pull "Main Disconnecf' switch on the Power Distribution Panel to "OFF." Also turn off exciter field switch.) e. Turn off safety switch and remove key. 8. Procedure for attaching any explosive device (such as CST, FIT, FT, BST, perforating Guns, etc.) to the cable. a. Check voltage between the rig, Refer to step 9 for arming procedures. casing and cable armour. Eliminate a. Verify that Casing-to-Rig Voltage at source if present. monitor is reading less than 0.25V. b. Install safety grounding traps and b. Clear line of fire of all personnel. connect to unit. c. Attach explosive device to the head or c. Install Casing-to-Rig Voltage collar locator. The individual performing monitor. this operation must have the safety switch d. DO NOT PROCEED WITH key in his possession at this time and OPERATIONS IF RESIDUAL VOLTAGE IS IN EXCESS OF 0.25V. retain it until the tool is 100 ft below ground level. e. Put out sign reading "DangerExplosives - Turn Off - 2-Way Radios 9. Arming perforating guns (ONLY THE ENGINEER MAY ARM A GUN): - Radio Phones." f. Turn off all radio transmitters within a. If a thunderstorm threatens to arrive on location within 30 minutes, do not arm the 1000 ft of the well. Radios must be gun. disabled such that an incoming call b. The cable must be attached to the gun does not activate the transmitter. string before the bottom gun is armed. g. If the well is within 2 1/2 miles of a Guns that are not electrically connected large transmitter (radio or TV station), or if all wellsite transmitters to the cable when the head is attached (multicarrier selective switching systems) cannot be turned off, contact your may be armed immediately prior to their Division Engineer or Division use and then attached to the cable. Technical Manager. c. Confirm that line of fire is still clear. h. On water operations, install the positive grounding cable from truck to barge or OSU to generator skid.

d. Check gun wires for sparking. e. Trim gun wires and trim the Primacord. f. Insert biasting cap in Blasting Cap Safety Tube. g. Connect biasting cap wires to gun lead wires. h. Remove biasting cap from Safety Tube and crimp to Primacord, using Blasting Cap Crimping Pliers, or insert biasting cap in booster holder. i. Prepare gun for watertight seal. 10. Proceed into well. 11. Operational procedure in hole: a. At or below 100 R below ground level, turn on safety switch, restore AC power, etc. Proceed in hole. b. Tie in, position gun, and shoot. c. Come out of hole. At or below 100 ft below ground level, prepare the instrument cab as for explosives operations (7a-e and 9a). 12. All guns must be safely relieved of any trapped pressure immediately upon removal from well according to instructions in Perforating Manual. 13. If the gun(s) did not fire, immediately disarm the lowermost gun (using the procedure prescribed in the Perforating Manual) before the gun is disconnected from the cable. 14. After the job, check to see that all equipment brought to the well is loaded on the truck. 15. Police the area for Primacord remnants, charges, trash, etc.

Figure 7.8 8.5.4

STRAY VOLTAGE SAFETY

Electrical detonators used in perforating operations are susceptible to detonation caused by induced currents from stray voltage sources. Stray voltage may originate from many sources such as faulty electrical power distribution on the rig, electrical welding, cathodic protection and nearby radio frequency (RF) transmission. Stray voltage induced by faulty rig wiring is the easiest to locate and remedy; the other sources are often much more difficult to diagnose and eliminate. 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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Voltages induced in electrical detonation circuits by RF emissions are the most difficult to detect. This hazard is best eliminated by disabling the transmitter during the surface portions of the operation. When vital navigation or communication links make this impossible, a survey of the transmitter fields is necessary to determine the conditions under which the perforating operation may be attempted. As an alternative, Schlumberger offers a perforating system, S.A.F.E.* Slapper-Actuated Firing Equipment, for protection against both RF-induced stray voltages and those voltages induced by cathodic protection and welding. The S.A.F.E. system uses Exploding Foil Initiator (EFI) technology, which has proven resistant to stray voltage because of the high currents required for detonation. The following procedures are recommended for perforating with electrical, heat-type detonators: - Always use detonators with safety resistors. - Consider each perforating site independently. - Eliminate all sources of stray voltage to provide maximum safety. Safety procedures are described in more detail in the Wireline and TCP Operating Procedures sections. Equipment is also available to operate at temperatures and pressures beyond these levels. The choice of equipment depends on the situation in a particular completion . To provide appropriate equipment for hostile operations, advanced planning is recommended. In this section, the effects of temperature, pressure and fluid properties are briefly presented, along with information about the use of perforating guns in deviated wells. 8.5.5

HIGH TEMPERATURE AND PRESSURE

High temperature and pressure are factors in the choice of explosive type, carrier design and the wellsite operation itself. Wellsite operations are affected because the temperature rating for explosives is time dependent. The Schlumberger time and temperature ratings are established so that there is no degradation in perforator performance (penetration and entrance hole) up to the maximum rating, but for safety reasons, the one-hour or one-hundred hour ratings should never be exceeded. The chart in Fig. 7.9 shows the time-temperature ratings for the explosives used in Schlumberger-manufactured perforating guns. Refer to the Gun Systems chapter for ratings of individual guns.


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700

Temperature (°F)

600

500 HNS 400

300 HMX 200 RDX

1

10

100

200

1000

Exposure time (hr) Figure 7.9

Explosive type RDX HMX HNS

1-hour Rating 330°F [166°C] 400°F [204°C] 500°F [260°C]

100-hour Rating 200°F [ 93°C] 300°F [149°C] 460°F [238°C]

Exceeding the time-temperature ratings may have serious results. Shaped charges and detonating cord in a sealed carrier or capsule may autodetonate low-order when exposed to temperatures above their ratings. This will result in a bomb-like effect with severe deformation or destruction of the carrier (or capsule) and possible well damage and sticking of the gun. Autodetonation of the detonator, on the other hand, will result in high-order initiation of the ballistic chain (detonating cord and charges) resulting in perforation of the well. Hydrostatic pressure and the type of fluid that surround the perforating gun are also important considerations. Exceeding a carrier's pressure rating may result in flooding the guns or crushing the carrier. This, in turn, may cause a low-order detonation and a bomb-like effect possibly damaging the well and sticking the gun. Also, minimum pressure ratings should be observed to prevent excessive swell and/or splitting of the carrier, resulting in possible sticking of the gun in casing, tubing or small restrictions. The ability of a carrier to withstand the forces that occur during perforating is related to whether its fluid environment is liquid or gas.


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The ratings given for Schlumberger's guns in the Gun Systems section include both minimum and maximum pressures. In most cases they include the capability for the carrier to survive shots in air with no hydrostatic pressure. Also, the gun dimensions shown take into account worst-case effects; i.e., shooting at minimum pressure in air or liquid, de pending on the rating of the gun. In the case of exposed guns with pressure-sealed detonators, overpressuring may cause a highorder initiation of the ballistic chain. Guns equipped with these detonators should not be subjected to high pressures on the surface, such as during wellhead equipment pressure tests. High temperatures and pressures also affect the elastomers of the pressure seals. In high temperature/ high pressure operations, the seals should be changed between runs into the well to avoid failures. To meet the requirements for high temperature/pressure operations, Schlumberger offers perforation equipment certified according to the procedures of the joint industry Program to Evaluate Gun Systems (PEGS) to operate up to 25,000 psi [ 1700 bar] and at one-hour ratings of up to 500°F [260°C]. This equipment has been built according to quality-control specifications that ensure operations up to the rated conditions.

8.5.6

FLUID CHEMICAL PROPERTIES

Fluid chemical properties, such as concentrations of hydrogen sulphide [H2S] and acid, that will exist in the well during and immediately after perforating need to be considered in planning completion operations. In sufficient concentrations, hydrogen sulphide and acids will attack perforating guns, causing general corrosion and possibly hydrogen embrittlement that may lead to material failure. Factors affecting the degree to which hydrogen attack occurs include the aggressiveness of the environment, type of material, amount of stress the material is under, length of time it is exposed, and the pressure. Operations in the presence of H2S or acid require special precautions for perforating guns and their associated hardware. Perforating guns themselves are not hydrogen sulphide-proof as per the National Association of Corrosion Engineers, but the associated equipment (accessories, TCP firing heads, wireline cable) may be made so either routinely or by special arrangements. Perforating guns are more or less resistant to the effects of hydrogen attack depending on the factors discussed above. The following points should also be considered: - If inhibitors are used, care must be taken to use those that do not affect elastomers in the pressure seals. - Hollow-carrier perforating guns are generally preferred to exposed guns for operations in environments with high H2S concentrations (more than 2%) and when acids are used at high bottomhole temperatures (above 280°F [138°C]).


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MUD WEIGHT

In addition to the effects of hydrostatic pressure on the perforating guns, mud weight may affect the operation of TCP firing systems. High-density muds tend to segregate with time, and this affects both pressure-actuated firing systems and drop-bar and electrical firing systems. However, pressure-actuated firing heads are preferred to other firing systems when higher-density muds are used because the mud's ability to transmit pressure levels is generally less impaired than the ability of a drop bar to reach the firing head in this condition. To ensure that mud solids do not affect the operation of a firing head, a fluid isolation sub should be used.

8.5.8

WELL DEVIATION

Wells that are deviated beyond 45° may be a problem for wireline-conveyed perforating guns because of increased frictional forces on the cable, reduced gravitational force along the wellbore, and smaller clearance between the maximum rigid length of the gun and the casing ID at doglegs. The recommended maximum rigid tool length for various clearances and dogleg angles is shown in Table 7.3. Maximum rigid tool length versus clearance Dogleg severity (degree//100 ft) (D-d) 0.25 0.5 0.75 1 1.25 1.5 1.75 2 2.25 2.5 2.75 3 3.25 3.5 3.75 4 4.25 4.5 4.75

2 21.9 30.9 37.8 43.7 48.9 53.5 57.8 61.8 65.6 69.1 72.5 75.7 78.8 81.8 84.6 87.4 90.1 92.7 95.2

4 15.5 21.9 26.8 30.9 34.5 37.8 40.9 43.7 46.4 48.9 51.2 53.5 55.7 57.8 59.8 61.8 63.7 65.6 67.3

D= Hole ID (in.) d= Gun OD (in.)

6 12.6 17.8 21.9 25.2 28.2 30.9 33.4 35.7 37.8 39.9 41.8 43.7 45.5 47.2 48.9 50.5 52.0 53.5 55.0

8 10.9 15.5 18.9 21.9 24.4 26.8 28.9 30.9 32.8 34.5 36.2 37.8 39.4 40.9 42.3 43.7 45.0 46.4 47.6

10 9.8 13.8 16.9 19.5 21.9 23.9 25.9 27.6 29.3 30.9 32.4 33.9 35.2 36.6 37.8 39.1 40.3 41.5 42.6

12 8.9 12.6 15.5 17.8 19.9 21.9 23.6 25.2 26.8 28.2 29.6 30.9 32.2 33.4 34.5 35.7 36.8 37.8 38.9

14 8.3 11.7 14.3 16.5 18.5 20.2 21.9 23.4 24.8 26.1 27.4 28.6 29.8 30.9 32.0 33.0 34.1 35.0 36.0

16 7.7 10.9 13.4 15.5 17.3 18.9 20.4 21.9 23.2 24.4 25.6 26.8 27.9 28.9 29.9 30.9 31.9 32.8 33.7

18 7.3 10.3 12.6 14.6 16.3 17.8 19.3 20.6 21.9 23.0 24.2 25.2 26.3 27.3 28.2 29.1 30.0 30.9 31.7

20 6.9 9.8 12.0 13.8 15.5 16.9 18.3 19.5 20.7 21.9 22.9 23.9 24.9 25.9 26.8 27.6 28.5 29.3 30.1

22 6.6 9.3 11.4 13.2 14.7 16.1 17.4 18.6 19.8 20.8 21.9 22.8 23.8 24.7 25.5 26.4 27.2 28 28.7

24 6.3 8.9 10.9 12.6 14.1 15.5 16.7 17.8 18.9 19.9 20.9 21.9 22.7 23.6 24.4 25.2 26.0 26.8 27.5

26 6.1 8.6 10.5 12.1 13.6 14.8 16.0 17.1 18.2 19.2 20.1 21.0 21.9 22.7 23.5 24.2 25.0 25.7 26.4

28 5.8 8.3 10.1 11.7 13.1 14.3 15.5 16.5 17.5 18.5 19.4 20.2 21.1 21.9 22.6 23.4 24.1 24.8 25.5

30 5.6 8.0 9.8 11..3 12.6 13.8 14.9 16.0 16.9 17.8 18.7 19.5 20..3 21.1 21.9 22.6 23.3 23.9 24.6

Table 7.3

Between 45° and 65° deviation, wireline perforating operations can often be successfully completed with the aid of weights. The Table 7.4 lists the common available weights for wireline perforating. Beyond 65°, tubing-conveyed perforating (either on drillpipe/production tubing or on coiled tubing) is the preferred technique. Roller adapters and orienting equipment are available for TCP operations in highly deviated or horizontal wells.


ARPO


IDENTIFICATION CODE

Type

Service

33/8 111/16 2 3/8 1 11/16 1 21/8 13/8 11/16 1 1/8 2

Steel Steel Steel Steel Tung. Tung. Tung. Hi-dens Hi-dens

Standard Standard Standard Standard Standard Standard H2S H2S H2S

30

OF

46


OD (in.)

PAG

Length (in.) 60 48.4 48.4 45.8 72 72 72 72 72

Weight (lb) 150 30.4 42.7 19 74 104 48.5 61 105

Pressure Rating (psi) 20,000 20,000 20,000 20,000 20,000 25,000 20,000 25,000 25,000

0 1

Temperature Rating (°F) 450 450 450 450 450 450 450 500 500


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IDENTIFICATION CODE

31

OF

46


8.6

PAG

0 1

WIRELINE THROUGH-TUBING GUNS

Through-tubing guns are used primary for under-balance initial or subsequent conditions that have the tubing and bottomhole assembly already in place. Optimal underbalance can be applied to achieve clean, productive perforations while maintaining absolute well control. This kind of guns are designed specifically for use on an electric wireline cable. They include retrievable hollow carrier guns (Domed Scallop and Scallop guns) and exposed guns(Enerjet e HyperCap). A variety of charges is available for through-tubing guns, depending on the application. The hollow carrier and strip gun system offer selectivity to shoot more than one zone per run. Because load through-tubing guns contain only secondary high explosives, they are safe to transport and handle when all the procedures are observed. In Figure 7.10 is represented the shots geometry.

Damaged zone diameter

Perforation spacing (depending on shot density)

Open hole diameter

Crushed zone diameter

Perforation length

Phase angle

Figure 7.10


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IDENTIFICATION CODE

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OF

46


8.6.1

PAG

0 1

GUN SELECTION

Selecting the most appropriate gun depends on several factors, including: - internal diameter of nipples and valves in downhole assembly - bottomhole temperature and pressure - perforator performance and value - sensitivity to perforating debris - borehole fluid - required shot phasing and density - deviation and doglegs The minimum restriction in the downhole assembly is usually the primary limiting factor. In general, one should use the largest gun that can be accommodated by restrictions in the well. Penetration depth and entrance hole size usually increase with gun size since bigger charges are possible. They also increase using arm exposed gun rather then a hallow carrier gun. The hallow carrier guns, in confront of the exposed guns, are fully retrievable and are capable of withstanding high pressure and temperature. This guns can be run at very high speeds. Phasing and shot density are parameters that affect productivity. Increasing this parameters will increase productivity, according with various studies and field practice. The correct choice of this parameters has to be done consulting the guns constructor’s handbook. Figure 7.11 shows the flowing pressure distribution around wellbore in two cases of different phasing (0° and 180°).


ARPO

IDENTIFICATION CODE


33

OF

46


135

PAG

0 1

112

204 Perforation 181

158

Wellbore

135

112

204 Perforation 181

158

Wellbore

Figure 7.11

Doglegs in the well should be considered when planning for the maximum length (and diameter) of gun to be run. For deviations beyond 60 to 70°, electrical coiled tubing should be used to convey wireline through tubings-guns. The following gun size selection chart shows the guns available for selection parameters of tubing size, temperature and pressure. Through Tubing Guns Selection Casing/Tubing (in.) 3/8 2 23/8 23/8 23/8 3/8 2 27/8 27/8 7/8 2 7/8 1/2 2 ,3

Gun Type 3/8 1 in. Domed Scallop 111/16 in. Pivot Gun 111/16 in. Enerjet 11/16 1 in. HyperCap 11/16 1 in. Domed Scallop 21/8 in. HyperCap 21/8 in. Enerjet 1/8 2 in. Domed Scallop 1/8 2 in. 60°, 80° Scallop

Max. Temperature (°F) 500 330 365 300 500 250 415 500 500

Max. Pressure (psi) 25,000 12,000 20,000 10,000 25,000 5,000 20,000 25,000 25,000


ARPO


IDENTIFICATION CODE

34

OF

46


8.6.2

PAG

0 1

SPECIAL PRECAUTIONS

This kind of guns are often run with wellhead pressure control equipment. The lubricator should never be pressure tested with an armed perforating gun inside. A pressure leak in the gun or detonator could result in gun detonation. The use of a Wireline Safety Valve is recommended to avoid this hazard.

8.7

Wireline Casing Guns

Casing guns are used to perforate wells before the completion string has been run (or, in some cases, after it has been pulled) and are usually shot in overbalanced conditions to maintain well control. This kind of guns are designed specifically for use on an electric wireline cable. 8.7.1

GUNS SELECTION

Selecting the most appropriate gun depends on several factors, including: - casing internal diameter - bottomhole temperature and pressure - perforator performance and value - deep penetration or big hole application - required shot phasing and density The casing internal diameter must be considered so that the best perforator performance compatible with casing size can be achieved. Penetration depth and entrance hole size usually increase with gun size since bigger charges are possible. In general, one should use the largest gun that can be accommodated by the casing. The following table shows the recommended casing guns for different casing size. Casing Guns Selection Casing/Tubing (in.) 41/2 41/2 5 51/2 51/2 7

Gun Type 31/8 in. HEG 33/8 in. PPG 33/8 in. PPG 4 in. PPG 4 in. PPG 5 in. PPG

Max. Temperature (°F) 210 400 400 400 210 330

Max. Pressure (psi) 4,000 25,000 25,000 25,000 4,000 25,000

The type of completion will dictate the choice of perforator charge type, either deep penetration or big hole charges. Deep penetrating charges are the usual choice for natural and stimulated completion. DP charges that penetrate beyond the damaged zone next to the borehole give the best well productivity. Big hole charges are normally used in gravel-packed completions. Phasing and shot density are parameters that affect productivity. Increasing this parameters will increase productivity, according with various studies and field practice. The correct choice of this parameters has to be done consulting the guns constructor’s handbook.

8.8

Operative Perforating Techniques


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IDENTIFICATION CODE

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OF

46


8.8.1

PAG

0 1

WIRELINE PERFORATING TECHNIQUES

The basic wireline perforating string is made up of a cable head, a correlation device, a positioning device for through-tubing application and one or more guns. The cable head serves three functions: to connect the gun string to the electric wireline, to provide a controlled weak point to free the cable if the guns become stuck and to provide a fishing profile. Before perforating operations begin, a copy of the reference log on which the perforation intervals were selected should be obtained and the perforation intervals recorded on the perforation worksheet. The reference log may be an openhole or cased hole evaluation or perforating depth control log. A correlation nuclear/casing collar log should be run across the perforation interval to be perforated and should be on depth with the reference log (Fig. 7.12). If there is a depth difference between the reference log and the correlation log, the correlation log must to be corrected to the reference log depths. The correlation device is normally a casing collar locator (CCL) or a gun gamma ray (GR) with a CCL (GR/CCL). In order to help the correlation work, is recommended to use a “pup” joint, which is easily recognisable by the CCL, somewhere near (above) the perforation interval. Correlation log

Reference log

C

CCL

Nuclear misure point

GR

Correlation log is “C” too deep

CCL

GR

Figure 7.12 On through tubing gun system, a positioning device is used to orient the shots toward the casing and minimise the gun-to-casing clearance. Two types of positioning devices are spring and magnetic positioning devices. The gun is composed of a head to provide electrical and mechanical connection to the CCL or positioning device, the gun body and lower head or bottom nose. 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


IDENTIFICATION CODE

PAG

36

OF

46


0 1

In hollow carriers, the lower head provides pressure confinement and access to the detonating cord and electrical connections. If the guns are to be shot selectively, a selective switch adapter is also used. 8.8.2

TCP (TUBING-CONVEYED PERFORATING) TECHNIQUES

8.8.2.1

PREJOB PLANNING

Completion objectives must be considered carefully when planning the perforating operation. Non-standard or unusual conditions, such a high bottomhole temperatures and pressures, long exposure times, high well deviations, small restrictions or an H2S environment may call for special equipment and techniques. The reservoir and the type of completion form a unique set of conditions that determine the selection of various options: -the casing size and formation characteristics usually dictate the gun size and charge type -computer-generated simulations like help in selecting the best gun/charge option -selection of a suitable explosive package is based on the anticipated maximum exposure time of the gun string at or near bottomhole temperature -the requirements for well testing operations will affect the choice of TCP firing heads and accessories, and the size of perforating guns in some cases -formation characteristics together with safety and economic considerations determine the amount of underbalance and how it is established -the amount of underbalance, completion type and installation influence the selection of a firing system and accessories -accurate knowledge of the ID of all string restrictions is essential to choose the firing system and to plan for possible fishing tool, positioning tool or cutter runs. A detailed completion sketch including ID, OD, depth or length of all components and the exact location of the restrictions together with an intended job prognosis are used as a basis for review and discussion by all concerned parties. A typical TCP job prognosis includes: -rig floor assembly procedures for guns and firing systems -running-in procedure -depth control and packer setting -pressure testing sequence for tubulars -establishing underbalance -firing procedure -flow and cleanup periods -testing sequence -reversing and pulling out (temporary completion) -realising the guns (permanent completion) -contingency plans (misfire, fishing) Proper job planning requires that basic but important decisions be made in advance of the actual job: -insertion of radioactive pip tags in the casing (if necessary) -additional drilling to provide enough rathole (if guns are to be dropped) -equipment to handle the guns and any optional equipment:(pup-joint, crossover, fishing tools, 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


IDENTIFICATION CODE

PAG

37

OF

46


0 1

elevators, etc.)

8.8.2.2

TESTING REQUIREMENTS

Many TCP operations are conducted in conjunction with a well test utilising a downhole test valve for flow control. Combining perforating and testing operations provides a powerful means to evaluate the effectiveness of the completion itself as well as to gain valuable information about the reservoir. Impulse testing provides an evaluation of production potential and near-wellbore skin that allows for the planning of stimulation operations. Drillstem testing brings information about reservoir-wide parameters, including pressure, permeability, fluid properties, and the detection of reservoir features, such as faults and boundaries. Testing plants are an important consideration when planning TCP operations. The key factors include: -number, type and duration of tests to be run -packer type, operation, specifications, setting method -test tool operating pressures -string dimensions -tbg/csg/pckr tests -stimulation plans.

8.8.2.3

DOWNHOLE OPEN STRING SYSTEM

The downhole open string system (Fig. 7.13) is one of the simplest and most commonly used systems for temporary and permanent completions. It is suitable for moderately deviated oil wells in which the reservoir is not depleted and the desired underbalance is 500 to 1000 psi. The underbalance is achieved in several ways: -the tbg may be displaced with as lighter fluid, such as brine or diesel, or with nitrogen before the packer is set (if there isn’t a by-pass valve above the packer) -the tbg may be swabbed out after the packer is set -the tbg fluid may be lifted with nitrogen or gas through coiled tbg or gas-lift valves. The first one is the most often used technique. The use of nitrogen or coiled tbg is frequently excluded because of cost or availability. When a firing system is either a drop bar, a trigger charge or a wet connector firing system, a debris circulating sub is recommended. The sub is positioned 30 ft above the firing head, and the volume between the debris sub and the firing head is filled with a clean fluid.


ARPO


IDENTIFICATION CODE

PAG

38

OF

46


0 1

Figure 7.13

8.8.2.4

DOWNHOLE CLOSED STRING SYSTEM

The Downhole Open String System is used on temporary, permanent and workover completions in oil and gas wells with moderate deviation. It is especially well adapted to situation requiring a large underbalance or with existing perforations below the packer. The underbalance is achieved by filling the tubing to the required cushion height as it is run in the hole. The production valve below the packer remains closed until the packer is set. The valve is opened by the passage of a drop bar, the trigger charge firing head or the wet connector tool. Large underbalances are achievable with a closed system because the tbg may be run dry.


ARPO


IDENTIFICATION CODE

PAG

39

OF

46


0 1

In the case of the drop bar and trigger charge firing heads, a minimum hydrostatic cushion pressure of 300 psi with clean fluid is required. Also, the downhole temperature at the top of the cushion should be lower of the boiling point of the cushion fluid used. High underbalance can also be achieved using a surge-disc sub. The surge disc shatters as the drop bar or slickline tool passes through it. Precautions are needed to avoid excessive debris accumulation on top of the surge disc sub that would make it impossible to break the disc. A drop bar is commonly used in reperforating applications. The production valve, which is fastacting, one-shot sliding sleeve, is opened by rathole pressure as the bar passes through it This creates an instantaneous underbalaced condition below the packer just before the guns fire, allowing simultaneous backsurging of all perforations. A wet connector firing system may also be used to activate downhole accessories. This firing system may be run in conjunction with a Measurement While Perforating Tool (MWPT) to monitor the TCP operation and to estimate the reservoir characteristics. A gun release sub may be run with the string either as a safety joint (if the guns become stuck) or to drop off the guns after perforating. The gun release sub is usually positioned one joint above the production valve to keep the release sub clean or allow hydraulic actuation. After the guns are dropped, at least 60 ft of open casing should be left above the top shot on permanent completions to allow safe production logging.

8.8.2.5

TESTING/TCP SYSTEM (FIG. 7.14)

The annulus pressure firing system is ideally suited for Impulse and drillstem tests in which guns are run below a downhole test valve. The system operate at any deviation, is practical immune to debris, and does not require a fullbore string. The firing system is usually A Differential Pressure Firing (DPF) system. With the DPF, differential pressure between the annulus above the packer and rathole actuates the firing head. Therefore, guns cannot be fired before the packer is set. Annulus pressure from above the packer is ported to the firing head through the packer and slotted pipe via a packer conversion kit. As annulus pump pressure is increased at surface, the downhole test valve opens. At this time a pressure difference will be created across the packer with the cushion pressure below it and the annulus plus pump pressure above it. The firing head is set to fire at this pressure. Opening the test valve while simultaneously firing the guns is a possible option for applications in which open perforation exist in the well. Annulus pressure-operated reversing valves are set to operate at pressures well above those required to fire the guns to avoid the possibility of prematurely aborting the test. Underbalance may be established as a closed system with the downhole test valve. Alternatively, underbalance may be established as an open system, by circulating light fluid through the packer bypass or by displacing the tubing fluid with nitrogen.


ARPO


IDENTIFICATION CODE

PAG

40

OF

46


0 1

Figure 7.14 A gun release may be combined with the Fullbore Packer Conversion kit and may be operated eithermechanically or hydraulically. Alternatively, an automatic gun release may be used.

8.8.2.6

FIRING HEADS

Many TCP firing heads are available to fit a variety of completion needs. The main difference between firing heads is the method of actuation. The Differential Pressure Firing head (Fig. 7.15) is actuated by the differential pressure between the annulus above the packer and the rathole pressure below. The DPF includes these features: 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


IDENTIFICATION CODE

PAG

41

OF

46


0 1

-a safety spring disables the firing pin when the hydrostatic pressure is below 600 psi (250 psi optional), making the gun string safe on and near the surface -the packer must be sealed and the test valve must be open before the guns can be fired -the system is specifically designed to be combined with test tools -pressure equalisation prevents firing flooded guns. The Hydraulic Delay Firing head (Fig. 7.16) is an absolute firing head. It is actuated by tubing pressure shearing calibrated pins when a preset pressure level is reached, initiating a time delay period during which underbalance pressure is established before the guns are fired. Once the delay has expired, pressure at the firing head drives the firing pin into the detonator. The HDF includes these features: -a minimum of 150 - to 300- psi hydrostatic pressure is required to activate the firing pin, making the gun string safe on and near the surface -the adjustable firing delay makes the head suitable for operations with nitrogen -precision shear pins ensure accuracy in the firing pressure -pressure equalisation prevents firing flooded guns. The Bar Hydrostatic Firing (BHF) head (Fig. 7.17) is a drop bar actuated device. Once it is actuated, hydrostatic pressure drives the driving pin into the detonator. The BHF includes these features: -a minimum of 150 - to 300- psi hydrostatic pressure is required to activate the firing pin, making the gun string safe on and near the surface -the device has both uncomplicated design and operation -pressure equalisation prevents firing flooded guns. The Wet Connector Firing (WCF) head is actuated by electric current passed from the surface via wireline through a wet connector to a resistirised electric detonator. The WCF includes these features: -gun firing is under total control of the engineer at the surface -before perforating takes place, the wireline is mechanically latched to the firing head to prevent cable movement after firing -it may be combined with a Measurements While Perforating Tool with GR, CCL, pressure and temperature measurements to provide same-trip correlation, real-time pressure data and perforating. The Trigger Charge Firing system (Fig. 7.18) adapts either the absolute pressure, drop bar or jardown firing mechanism to a transfer assembly that is run into the well on slickline (or electric line) after the tubing string and guns have been run, tested and positioned. The absolute pressure and drop-bar versions have the same mechanism used in the HDF and BHF, respectively. The TCF includes these features: -heads containing primary explosives are run into the well latched and retrieved independently of the gun string 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


IDENTIFICATION CODE

PAG

42

OF

46


0 1

-the firing head is disconnected before gun retrieval -the choice of firing head may be made after guns have been run -drop bar, jar-down and HDF versions require a minimum of 150 - to 300 - psi hydrostatic pressure to be activated. Redundant firing system are available that allow the primary firing heads to be combined with one another as required. Both firing heads are located at the top of the gun string allowing the guns and heads to be made up safely, and both heads retain their full safety features.

8.8.2.7

FIRING HEAD ASSEMBLY

Each firing head assembly includes, from top to bottom: -any equipment attached to the firing head -the firing head including the detonator (or two firing heads if side-by-side redundant heads are used) -a fill sub, which provides the tensile support for the string and allows space for debris accumulation below the head -a firing head adapter to mechanically and balistically connect the firing head to the safety spacer and guns below. The firing head is made up vertically to the safety spacer positioned in the rotary table. The safety spacer provides a minimum 10 - ft [3 - m] blank section between the firing head assembly and the top shot of the upper gun in the string.


ARPO


IDENTIFICATION CODE

PAG

43

OF

46


0 1

Fig 7.15


ARPO


IDENTIFICATION CODE

PAG

44

OF

46


0 1

Fig 7.16


ARPO


IDENTIFICATION CODE

PAG

45

OF

46


0 1

Fig 7.17


ARPO


IDENTIFICATION CODE

PAG

46

OF

46


0 1

Fig 7.18


ARPO



TYPE OF ACTIVITY'

ISSUING DEPT.

DOC. TYPE

REF. N.

OF

TEAP

P

1

R

1

PAG.

34

8798


Volume 1

CHAPTER 9 - FORMATION DEMAGE DISTRIBUTION LIST TEAP STAP – Archive





€

Issued by:

REVISIONS

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



PREP'D

CHK'D

APPR'D


ARPO


IDENTIFICATION CODE

PAG

2

OF

34


0 1

INDEX

9. FORMATION DAMAGE ..................................................................................................................4 9.1 INTRODUCTION. .......................................................................................................................4 9.1.1 SIGNIFICANCE OF FORMATION DAMAGE....................................................................4 9.1.2 BASIC CAUSE OF DAMAGE...........................................................................................4 9.1.3 PLUGGING ASSOCIATED WITH FLUID FILTRATE. ......................................................5 9.1.4 CLASSIFICATION OF DAMAGE MECHANISM. ..............................................................5 9.1.5 REDUCED ABSOLUTE PERMEABILITY.........................................................................6 9.2 DAMAGE REDUCTION .............................................................................................................6 9.3 FORMATION CLAYS (INHERENT PARTICLES). .....................................................................7 9.3.1 OCCURRENCE OF CLAYS .............................................................................................7 9.3.2 CLAY MIGRATION...........................................................................................................7 9.3.3 CLAY STRUCTURE.........................................................................................................8 9.3.4 EFFECT OF WATER. ......................................................................................................8 9.4 ASPHALTENE PLUGGING. ......................................................................................................9 9.5 REDUCED RELATIVE PERMEABILITY. ..................................................................................9 9.6 INCREASED FLUID VISCOSITY...............................................................................................9 9.7 DIAGNOSIS OF FORMATION DAMAGE. ...............................................................................10 9.8 SURFACTANTS FOR WELL TREATMENTS..........................................................................10 9.8.1 CHARACTERISTICS OF SURFACTANTS. ...................................................................10 9.8.2 WETTABILITY................................................................................................................11 9.8.3 MECHANICS OF EMULSIONS ......................................................................................11 9.8.4 FORMATION DAMAGE SUSCEPTIBLE TO SURFACTANT TREATMENT...................12 9.8.5 WATER BLOCKS. .........................................................................................................12 9.8.6 EMULSION BLOCKS .....................................................................................................13 9.8.7 PARTICLES BLOCK. .....................................................................................................13 9.8.8 SUSCEPTIBILITY TO SURFACTANT-RELATED DAMAGE. .........................................14 9.8.9 PREVENTING OR REMOVING DAMAGE. ....................................................................14 9.8.10 SELECTION OF AN EMULSION BREAKING SURFACTANT. ....................................15 9.8.11 REQUIREMENTS FOR WELL TREATING SURFACTANTS. ......................................15 9.8.12 WELL STIMULATION WITH SURFACTANTS. ............................................................15 9.9 ACIDIZING...............................................................................................................................16 9.9.1 ACIDS USED IN WELL STIMULATION. ........................................................................17 9.9.2 ACID ADDITIVES...........................................................................................................18 9.9.3 CARBONATE ACIDIZING. .............................................................................................19 9.9.4 FACTORS CONTROLLING ACID REACTION RATE. ...................................................20 9.9.5 RETARDATION OF ACID. .............................................................................................20 9.9.6 ACIDIZING TECHNIQUES FOR CARBONATE FORMATION. ......................................21 9.9.7 MATRIX ACIDIZING CARBONATE FORMATIONS. ......................................................21 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


IDENTIFICATION CODE

PAG

3

OF

34


0 1

9.9.8 FRACTURE ETCHING IN HOMOGENEOUS CARBONATES. ......................................22 9.9.9 SUMMARY OF USE OF HIGH STRENGTH ACID. ........................................................24 9.9.10 SANDSTONE ACIDIZING. ...........................................................................................24 9.9.11 PLANNING HF ACID STIMULATION. ..........................................................................25 9.9.12 ADDITIVES FOR SANDSTONE ACIDIZING ................................................................25 9.9.13 CLAY STABILISATION. ...............................................................................................26 9.9.14 PREFLUSH FOR SANDSTONE ACIDIZING OF OIL WELLS......................................27 9.9.15 HF-HCI ACID TREATMENT FOR OIL WELLS.............................................................27 9.9.16 STIMULATION OF GAS WELLS, GAS INJECTION WELLS, AND WATER INJECTION WELLS ................................................................................................................27 9.9.17 IN-SITU HF GENERATING SYSTEM (SGMA)20. ........................................................28 9.9.18 CLAY ACID. .................................................................................................................28 9.9.19 POTENTIAL SAFETY HAZARD IN ACIDIZING............................................................28 9.10 SCALE DEPOSITION, REMOVAL, AND PREVENTION.......................................................29 9.10.1 INTRODUCTION. .........................................................................................................29 9.10.2 LOSS OF PROFIT. ......................................................................................................29 9.10.3 CAUSES OF SCALE DEPOSITION.............................................................................29 9.10.4 PREDICTION AND IDENTIFICATION OF SCALE. ......................................................32 9.10.5 IDENTIFICATION OF SCALE. .....................................................................................32 9.10.6 SCALE REMOVAL.......................................................................................................32 9.10.7 SCALE PREVENTION. ................................................................................................33 9.11 CONCLUSIONS ....................................................................................................................34


ARPO


IDENTIFICATION CODE

9.1

4

OF

34


9.

PAG

0 1

FORMATION DAMAGE

INTRODUCTION.

All wells are susceptible to formation damage to some degree, from relatively minor loss of productivity to complete plugging of specific zones.

9.1.1

SIGNIFICANCE OF FORMATION DAMAGE.

Flow surveys almost invariably show that a high percentage of the zone open to the wellbore is not contributing to the total flow. With the inherent barriers to vertical flow present in most zones, formation damage can restrict or prevent effective depletion. Thus reserves may remain trapped in a high percentage of the potentially productive zone. For many situations, complete restoration of productivity is not possible. Formation damage means reduced current production.

9.1.2

BASIC CAUSE OF DAMAGE.

Contact with a foreign fluid is the basic cause of formation damage. This foreign fluid may be a drilling mud, a clean completion or workover fluid, a stimulation or well-treating fluid, or even the reservoir fluid itself if the original characteristics are altered. Most oilfield fluids consist of two phases—liquid and solids. Either can cause significant formation damage through one of several possible mechanisms. Plugging Associated with Solids. Plugging by solids occurs on the formation face, in the perforation, or in the formation. Solids may be weighting materials, clays, viscosity builders, fluid loss-control materials, lost-circulation materials, drilled solids, cement particles, perforating charge debris, rust and mill scale, pipe dope, undissolved salt, gravel pack or frac sand fines, precipitated scales, or paraffin or asphaltenes. Large Solids. Large solids cause formation damage by plating out on the face of a filter media. Plugging may occur in a perforation tunnel, on the face of an open hole zone, on the face of a natural or created fracture, or in a fracture channel. Sometimes, the plated-out solids may be removed by reverse flow. However, many times it is not possible to achieve sufficient differential pressure at the right point. With the existence of inherent barriers to vertical flow, many zones may remain partially or completely sealed for the life of the well. Small Solids. Very small solids such as iron oxides, clays, or other silicate particles may be carried for some distance into the pores of relatively permeable formations to create serious plugging. In frac jobs or gravel packing operations, fines are frequently carried in or created by the treating fluids, then held in place by the frac sand or gravel to reduce fracture flow capacity or cause an internal plug in the gravel pack. 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


IDENTIFICATION CODE

PAG

5

OF

34


0 1

Solids Precipitation. Solids may also be precipitated within the formation. For example, scale often precipitates due to mixing of incompatible waters; asphaltene or paraffin may be precipitated due to changing equilibrium conditions. 9.1.3

PLUGGING ASSOCIATED WITH FLUID FILTRATE.

The liquid filtrate may be water containing varying types and concentrations of positive and negative ions and surfactants. It may be a hydrocarbon carrying various surfactants. The liquid is forced into porous zones by differential pressure, displacing or commingling with a portion of the virgin reservoir fluids. This may create blockage due to one or more of several mechanisms that may reduce the absolute permeability of the pore, or restrict flow due to relative permeability or viscosity effects. Particle migration effects include hydration or dehydration of clays; dispersion or flocculation of highly swellable or slightly swellable clays and formation particles; or dissolution of cementing materials allowing fines. Increased water saturation causes waterblocking o reduced relative permeability to oil or gas. Liquid filtrate may create a viscous emulsion with the virgin reservoir oil or water or may tend to oil wet the rock, reducing relative permeability to oil. Stable emulsions within a formation appear to be associated with partially oil-wet systems. Viscosity effects include emulsions, but also plugging by a high-viscosity treating fluid, which for some reason does not "break" or is not sufficiently diluted to readily return to the wellbore under the influence of the available differential pressure. 9.1.4

CLASSIFICATION OF DAMAGE MECHANISM.

The numerous mechanisms that result in formation damage may be generally classified as to the manner by which they decrease production: Reduced absolute permeability of formation results from plugging of pore channels by induced or inherent particles. Reduced relative permeability to oil results from an increase in water saturation or oil-wetting of the rock. Increased viscosity of reservoir fluid results from emulsions or high-viscosity treating fluids. In a radial flow system, any reduction in permeability around the wellbore results in serious reduction of productivity or injectivity. In a linear flow situation, some plugging of the face of the fracture can be tolerated due to the large area represented by the faces of the fracture. However, plugging of the fracture itself results in serious reduction in productivity or injectivity.


ARPO


IDENTIFICATION CODE

6

OF

34


9.1.5

PAG

0 1

REDUCED ABSOLUTE PERMEABILITY.

This results from plugging of pore channels by induced or inherent particles

9.1.5.1

PARTICLE PLUGGING WITHIN THE FORMATION.

The pore system provides a tortuous path to the wellbore. Recent laboratory techniques, including the scanning electron microscope, have provided a clearer picture of particle plugging within the formation pore system, both by particles inherent to the formation and by particles carried into the formation by various fluid filtrates. Particles can move through the pore system. Electron microscope pictures of sandstones show that even clean sands contain a relatively large amount of small particulate materials. These particles, clays, feldspar, and other minerals, appear to be stuck to the rock matrix; however, lab tests indicate that if the flow velocity reaches a high enough level, these particles can be picked up and moved from one pore cavern to another. If the next pore cavern is larger and flow velocity drops, the particle may settle out. If several particles moving through the caverns meet pore restrictions having an opening less than about three times the particle size, they will bridge. Such bridging, causing partial or complete plugging, will force fluids to seek other paths to the well-bore. Particle movement is affected by wettability and by the fluid phases in the pore system. Loss of filtrate may produce single-phase flow on cleanup. Following completion or workover operations where the wellbore has been filled with a kill fluid, the formation pore system contains a very high saturation of the kill-fluid filtrate. The initial flow through the pore caverns near the wellbore occurs essentially as a single-phase flow. A water filtrate produced back at a high rate could cause severe plugging due to bridging of inherent formation particles which, under normal producing conditions, might not be free to move. More important, the filtrate will have carried into the pore system thousands of foreign particles. Thus, as the well is put on production, the pore system around the wellbore will be loaded with moveable inherent and induced particles. Plugging by particles is rate sensitive. At high rates, randomly dispersed particles apparently tend to interfere with each other as they approach pore constrictions and finally bridge. At low flow rates, however, particles are in more gentle movement and may either (1) gradually align themselves so that one by one they can work their way through the constriction without bridging, or (2) are displaced in the water envelope to a nonblocking position out of the main flow stream. In core tests, gradual increases in flow rates provided higher ultimate permeabilities than did onestep increases to the same flow rate. Once a bridge is formed by high flow rates, efforts to displace it by backflow have been only sporadically successful.

9.2

DAMAGE REDUCTION

An important consideration in reducing formation damage due to particle plugging in the formation is to eliminate all possible sources of particles extraneous to the formation. Well-killing fluids are an obvious source of extraneous particles. Usually, cation content is adjusted to prevent disturbance of


ARPO


IDENTIFICATION CODE

PAG

7

OF

34


0 1

formation clays, but, with little fluid loss control, a large amount of fine particles are carried into the formation. Although this cannot be prevented entirely, these steps are in the right direction: 1. Surface fluid tanks and workover tubulars must be clean. Apply pipe dope sparingly to the pin with a small brush. 2. Filter all fluids through a 2-micron filter at the surface. 3. Add oxygen scavenger to flow system to prevent formation of iron oxide particles downhole. A sequesterant should be used to prevent formation of iron hydroxide. 4. Reduce hydrostatic pressure of wellbore fluid to a near balanced or even under balanced condition relative to formation pressure. These precautions will reduce permeability reduction even if large amounts of the clean brine are lost to the formation. If fluid loss control is necessary, powdered calcium carbonate sized for bridging can be used. The resulting "mud cake" can be at least partially removed with hydrochloric acid. However, if large amounts of calcium carbonate fines enter the formation pore system, complete removal is limited due to bypassing and fingering of the acid. It is also important that fine particles as well as the rock surfaces be left in a water-wet condition after completion, workover, or well treatment. The fact that bridging by particles at pore constrictions is rate sensitive suggests that cleaning of a well after completion or workover using high flow rates should be avoided. Laboratory data, backed up by field experimentation, show that particles free to move in the pore channels around the wellbore can be best removed by initiating production slowly and by gradually increasing production rate until the desired producing rate is reached.

9.3

FORMATION CLAYS (INHERENT PARTICLES).

9.3.1

OCCURRENCE OF CLAYS

Nearly all oil-producing sandstones contain some clays occurring as a coating on individual sand grains and/or discrete particles mixed with the sand. Carbonate rocks may also contain clays. Frequently, however, these clays are encapsulated in the rock matrix and are not seriously affected by invading fluids. A sand that contains 1 to 5% clay is usually termed a "clean" sand. A dirty sand may contain 5 to greater than 20% clay. Clays most frequently found in hydrocarbon zones are montmorillonite (bentonite), illite, mixed-layer clays (primarily illite-montmorillonite), kaolinite, and chlorite. The name, Smectite, seen in current literature refers to Montmorillonite.

9.3.2

CLAY MIGRATION.

All clay types are capable of migrating when contacted by a foreign water which alters the ionic environment. Examples of foreign waters are filtrate loss from drilling fluids, cement, completion


ARPO


IDENTIFICATION CODE

PAG

8

OF

34


0 1

fluids, workover fluids, and stimulation fluids. In the case of montmorillonite and mixed-layer clays, a change in size due to swelling or water retention enhances their probability of migrating. A dehydrated clay particle has a diameter of about 4 microns compared to a pore size in an average sandstone of 10 to 100 microns. It should be remembered that high flow rate alone (even with no change in environmental conditions) is sufficient to cause particle migration. Thus, anytime a clay (or other fine particle) is present, it can be assumed that permeability damage may occur. The degree of damage will depend on the type and concentration of clays or particles present, their relative position in the rock, the severity of the ionic environmental change, and, to an extent, the rate of fluid flow.

9.3.3

CLAY STRUCTURE.

Clay crystals are thin platelets which under normal conditions of deposition are oriented in deck-ofcards stacks or packets. Surface area of clay packets may be very high. Dispersed montmorillonite may have a surface area of 750 sq m/gm, whereas sand grains have a surface area of 150-200 sq cm/gm. Mixed-layer clays are composed of more than one clay mineral. Irregular mixed-layer clays usually contain montmorillonite and illite, and show definite swelling characteristics.. Another example of a mixed layer clay is the montmorillonite-chlorite intergrade. However, this type is not nearly as prevalent as the montmorillonite-illite mixed layer clay.

9.3.4

EFFECT OF WATER.

Montmorillonite is the only clay that swells by adsorbing ordered water layers between crystals. Mixed-layer clay, which contains montmorillonite, will also swell, but the illite portion of this clay is only slightly swellable. Kaolinite, chlorite, and illite may be classed as slightly swellable clays. Their crystals tend to remain in packets instead of being dispersed like montmorillonite crystals; however, they do adsorb some water. Hydration of cations. Swelling of clays in contact with water is due to the hydration of the cations attached to the clay and hydrogen bonding. The degree of swelling depends on the cation adsorbed on the clay and the amount of salts dissolved in the water contacting the clay. Effect of cation type and concentration. When a montmorillonite clay in equilibrium with a particular formation brine is contacted by water having different salts, a cation exchange may occur. Calcium, a divalent ion, is quite effective in replacing monovalent ions, particularly sodium. Potassium is more effective than sodium in replacing calcium. This cation exchange may cause the size of the clay particle to change. Potassium montmorillonite undergoes very little swelling when contacted with water containing at least 0.4% potassium chloride. Clay dispersion affected by pH. Scanning electron microscope studies have confirmed the effect of pH on clay particle disturbance. Clay particles in core pore spaces were significantly disturbed and thus made mobile in contact with 8 pH fluid. This effect was more noticeable when contacted with 10 ph fluid. Virtually no disturbance was noted when similar core samples were contacted with a 4 pH fluid.


ARPO


IDENTIFICATION CODE

PAG

9

OF

34


0 1

Control of Clay Damage. When clay particles in sandstones are rearranged or disturbed in any manner it is usually impossible to restore the original permeability; thus, formation damage due to clays must be prevented rather than cured. In virgin formation , the degree of swelling of a clay particle is in equilibrium with the type and concentration of salts in the connate water. Thus, clean formation water used in workover operations should not disturb this balance. The clay can be cemented in place using Zirconium Oxychloride which creates a poly- nucleated cations that bond strongly the clay particles together. This system is stable with HCl but is removed by HF. Multy-nuclei organic polymers (Halliburton Cla-Sta and Dowell L53) are stable with HCl and for at least one hour with HF-HCl (3-12)

9.4

ASPHALTENE PLUGGING.

Temperature and pressure reductions accompanying flow of crude oil and containing appreciable quantities of asphaltic material may result in deposition of these materials in the formation. Deposition may reduce formation permeability by blocking pore spaces. or by causing the formation to become oil wet.

9.5

REDUCED RELATIVE PERMEABILITY.

Increased water saturation near the wellbore results from filtrate invasion or fingering or coning of formation water. Filtrate invasion is normally termed “ water blockage”. The extent of oil productivity reduction depends on the degree of water saturation and the radius of the affected area.

9.6

INCREASED FLUID VISCOSITY.

Plugging of the formation may occur due to the presence of emulsions in the pores of the formation. In a radial flow situation, the extent of productivity reduction depends on viscosity of the emulsion and the radius of the affected area. Water-in-oil emulsions generally exhibit viscosities many times higher than the viscosities of oil-in-water emulsions. Present evidence indicates that rarely does indigenous oil and water create emulsion blocks. Emulsion blocks probably occur when oil injected into formation becomes emulsified with formation water or when extraneous water enters the formation and becomes mixed with the oil phase. Usually, energy is required to form an emulsion, and a stabilising mechanism is required to maintain the emulsion. Required energy exists in the restricted flow path areas around the wellbore where flow from all directions converges to move in toward a perforation. Emulsions are stabilised by surface active materials and by small solid particles such as formation fines, drilling or completion fluid clays, or solid hydrocarbon particles. Cationic surfactants (corrosion or scale inhibitors, biocides, and even surface emulsion breakers) often tend to stabilise water-in-oil emulsions.


ARPO


IDENTIFICATION CODE

PAG

10

OF

34


0 1

The presence and the character of ''fines" contribute significantly to emulsion stability. These fines may occur because of the character of the formation—or may be released as a result of a stimulation treatment or contact with a foreign fluid. Generally, fine-particle wettability is an important factor in emulsion stability and in determining the continuous phase of the emulsion. Strongly waterwet fines tend to reduce emulsion stability. The formation wettability is a significant factor in emulsion stability. Emulsions exhibit much greater stability and viscosity in strongly oil-wet formations. Emulsion blocks exhibit a "check valve" effect which can be detected by comparing injectivity and productivity tests. Emulsion blockage is normally treated with surfactants. Emulsion formation can usually be prevented by including a carefully selected surfactant in well treatments.

9.7

DIAGNOSIS OF FORMATION DAMAGE.

It is usually possible to determine that formation damage or "skin effect" exists in a particular well. This can be done through well tests such as injectivity or productivity tests. Analysis of pressure build-up or fall-off tests may indicate the relative magnitude of the damage or skin effect. Production logging surveys may show zones not contributing to the total flow stream. Careful examination of well completion reports or workover reports is sometimes helpful. Liberal reading between the lines is usually necessary to tie down significant clues. This can be done effectively only if the "detective" is well grounded in well operations in the field as well as being knowledgeable on formation damage mechanisms.

9.8

SURFACTANTS FOR WELL TREATMENTS

Well Treatments. Surfactant characteristics. Action of surfactant types. Damage susceptible to surfactant treatment. Surfactant selection. Well-treatment techniques. Surfactants, or surface-active agents, are chemicals that can favourably or unfavourably affect the flow of fluids near the wellbore. The use of surfactants should be considered for all well completion, well killing, workover, and well stimulation. To appreciate the role of surfactants, it is necessary to understand the operation of liquids. In the bulk volume of a liquid, molecules exert a mutual attraction for each other. This force, a combination of Van der Waals' forces and electrostatic forces, is balanced within the bulk of a liquid but exerts "tension" at the surface of the liquid. Similar effects take place between two immiscible liquids, or between a liquid and a rock or metal surface.

9.8.1

CHARACTERISTICS OF SURFACTANTS.

A surface-active agent, or surfactant, can be defined as a molecule that seeks out an interface and has the ability to alter prevailing conditions. Chemically, a surfactant has an affinity for both water


ARPO


IDENTIFICATION CODE

PAG

11

OF

34


0 1

and oil. The surfactant molecule has two parts—one part that is soluble in oil and another part that is soluble in water The molecule is thus partially soluble in both water and oil. This promotes the surfactant accumulation at the interface between two liquids, between a liquid and a gas, and between a liquid and a solid. A surfactant with stronger affinity for oil is usually classed as oil soluble, and one with a stronger attraction for water is classed as water soluble. Some surfactants are classed as water or oil dispersible. Surfactants can bring about the following changes in reservoir fluids and reservoir rocks: 1. Raise or lower surface and interfacial tension. 2. Make, break, weaken, or strengthen an emulsion. 3. Change the wettability of reservoir rocks and casing, tubing, or flowline 4. Disperse or flocculate clays and other fines. Surfactants have the ability to lower the surface tension of a liquid that is in contact with a gas by adsorbing at the interface between the liquid and gas. Surfactants can also reduce interfacial tension between two immiscible liquids by adsorbing at the interfaces between the liquids. Because the primary action of most surfactants is due to electrostatic forces, a surfactant is classified by the ionic nature of the molecule's Water-Soluble group. Anionic surfactants are organic molecules where the Water-Soluble group is negatively charged. (phosphonates). Cationic surfactants are organic molecules where the water-soluble group is positively charged. Non-ionic Surfactants are organic molecules that do not ionise and, therefore, remain uncharged. Amphoteric Surfactants are organic molecules where the water-soluble group can be either positively charged, negatively charged, or uncharged.

9.8.2

WETTABILITY.

Wettability is a descriptive term used to indicate whether a rock or metal surface has the capacity to be preferentially coated with a film of oil or a film of water. Surfactants may adsorb at the interface between the liquid and rock or metal surface and may change the electrical charge on the rock or metal, thereby altering the wettability. Although the surface of a solid can have varying degrees of wettability under normal reservoir conditions, these conditions usually exist: Sand and clay are water-wet and have a negative surface charge. Limestone and dolomite are water-wet and have a positive surface charge in the pH range of O to 8.

9.8.3

MECHANICS OF EMULSIONS

Emulsions can occur between two immiscible liquids and may be stable depending on effects that occur at the interface. Energy is required to create the emulsion, and stabilisers must collect at the interface between the liquids to keep the emulsion from breaking. The most significant stabilisers of emulsions are: 1. Fine particles of clay or other materials 2. Asphaltenes 3. Surfactants


ARPO


IDENTIFICATION CODE

PAG

12

OF

34


0 1

Surfactants have the ability to break an emulsion by acting on the stabilising materials in such a way as to remove them from the interfacial film surrounding an emulsion droplet.

9.8.4

FORMATION DAMAGE SUSCEPTIBLE TO SURFACTANT TREATMENT.

A number of types of formation damage can be prevented or alleviated with surfactant. Type of damage which may be prevented, alleviated or aggravated by surfactants are: Oil-wetting of formation rock. Water blocks. Viscous emulsion blocks. Interfacial film or membrane blocks. Particle blocks caused by dispersion, flocculation or movement of clays or other fines. Flow restriction caused by high surface or interfacial tension of liquid Oil-Wetting. Oil-wetting a normally water-wet formation can reduce permeability to oil by 15 to 85% with an average reduction of about 40%. When the formation near the wellbore becomes oil-wet, oil is preferentially attracted to the surface of reservoir rock. This appreciably increases the thickness of the film coating the reservoir rock and reduces the size of flow paths from the reservoir as well as decreasing the relative permeability to oil. Gas wells are also adversely affected by oil-wetting the formation. Oil-wetting a reservoir rock can result in severe water or emulsion blocking. Sources of oil-wetting in oil and gas wells are: Surfactants in some drilling mud filtrates and workover and well stimulation fluids may oil-wet the formation. Corrosion inhibitors and bactericides are usually cationic surfactants, which will oil-wet sandstone and clay. Oil-base mud containing blown asphalt will oil-wet sandstone, clays, or carbonates. Oil emulsion muds usually contain considerable cationic surfactants and may oil-wet sandstones and clays. A strong water-wetting surfactant may convert some oil-wetted surfaces to water-wet surfaces. This will enlarge flow paths to oil and restore oil permeability to that of the undamaged water-wet matrix around the wellbore. However, cationic surfactants are extremely difficult to remove from sandstone and clay. The best approach is to avoid contact of formation sands and clay with cationic surfactants.

9.8.5

WATER BLOCKS.

When large quantities of water are lost to a partially oil-wet formation. the return of original oil or gas productivity may be slow, especially in partially pressure-depleted reservoirs. This problem is caused by a temporary reduction in relative permeability near the wellbore to oil or gas. It is usually selfcorrecting but may persist for months or years. Water blocking can usually be prevented by adding to all injected well fluids about 0.1 to 0.2% by volume of surfactant selected to lower surface and interfacial tension. The surfactant should also water-wet the formation and prevent emulsions.


ARPO


IDENTIFICATION CODE

PAG

13

OF

34


0 1

Cleanup of a water-blocked well can be accelerated by injecting into the formation a solution. of 1% to 3% by volume of a selected surfactant in clean water or oil. The surfactant should lower surface and interfacial tension and leave the formation in a water-wet condition. Removing damage requires many times the volume of surfactant required to prevent damage.

9.8.6

EMULSION BLOCKS

Viscous emulsions of oil and water in the formation near the wellbore can drastically reduce the productivity of oil or gas wells. In carbonates, emulsions are usually associated with fracture acidizing. Emulsions in the formation can be broken by injecting demulsifying surfactants into the formation, provided intimate contact is made between the surfactant and each emulsion droplet. To break the emulsion, the surfactant must be absorbed on the surface of the emulsion droplets and lower interfacial tension. Breaking an emulsion in the formation usually requires the injection of 2% to 3% by volume of demulsifying surfactant in clean water or clean oil. The treatment volumes should be at least equal to or greater than the volume of the damaging fluid previously lost to the formation. The amount of surfactant required to remove an emulsion block will usually be 20 to 30 times the volume of surfactant required to prevent the block. Diagnosis of emulsion block—It has been proved that if an emulsion block exists, the calculated average well permeability as determined by injectivity tests will be manifold higher than the average permeability determined from production tests. This provides a reliable way to predict emulsion blocks and is frequently called the ''check valve" effect.

9.8.6.1

INTERFACIAL FILM OR MEMBRANE.

Film forming materials including surfactants, can be absorbed at the Oil-water interface and cause formation plugging. Surfactantants may Sometimes cause film to resolubilize in oil and thus reduce formation blocking.

9.8.7

PARTICLES BLOCK.

As a rule, it is desirable to maintain formation clays in the original condition in the reservoir. Dispersing, flocculating, breaking loose, or moving clays probably causes more damage to wells than the swelling clays. Change of particle size affects formation damage. Oil wetting of clays with cationic surfactants greatly increases the size of clay particles and increase the severity of clay-blockage. Hydrated sodium clays may reduced in size by an HCl treatment. When a hydrated sodium clay reacts with + + acid, the hydrogen ions (H ) will replace the sodium ions (Na ) by ion exchange. An anionic surfactant should usually be used when acidizing sandstone to prevent clay flocculation. High surface tension of liquids near the wellbore will reduce the flow of oil and gas into a well and increase well cleanup time. A selected surfactant may be added to lower surface tension and accelerate well clean up.


ARPO


IDENTIFICATION CODE

PAG

14

OF

34


0 1

A correct surfactant, which is designed for specific well conditions, can lower surface and interfacial tension, favourable change wettability, break or prevent emulsions, prevent remove water blocks. The proper use of surfactants during well completion workover or well stimulation can prevent or remove many types of damage and result in increased productivity or injectivity.

9.8.8

SUSCEPTIBILITY TO SURFACTANT-RELATED DAMAGE.

Sandstone wells are usually more susceptible to damage caused by oil-wetting, emulsion blocks, water blocks, and changes in clays than limestone wells. Since most cationic surfactants will oil-wet clay and sandstone and stabilise water-in-oil emulsions, caution should be exercised in the use of cationics in sandstone reservoirs. This precaution applies to sandstone acidizing and to all other fluid injection or circulation activities. Organic corrosion inhibitors and bactericides are usually cationic surfactants. Before squeezing any cationic corrosion inhibitor into a sandstone formation, laboratory tests should be run on formation cores to determine the effect of the specific corrosion inhibitor on formation permeability. Caution should be exercised in using saltwater or oil from treaters or field stock tanks treated with cationic emulsion breakers if emulsion or waterblocking appears to be a problem. The damaging effects of the cationic surfactants may sometimes be overcome by adding carefully selected surfactants and/ or mutual solvents. Sandstone wells producing low gravity asphaltic crude are more susceptible to damage from oilwetting, emulsion-blocking, and water-blocking. A 24 to 72-hr solvent-surfactant soak followed by an HF acid treatment is usually the best treatment for wells that contain a high percentage of asphaltenes. Above 37° API, the asphaltene content in crude is usually too low to promote formation damage. Emulsion-blocking and water-blocking are usually not a problem in limestone and dolomite wells except during acidizing. When it is anticipated that appreciable undissolved fines will be released in fracture acidizing of carbonates, it may be desirable.

9.8.9

PREVENTING OR REMOVING DAMAGE.

Emphasis in the use of surfactants should be aimed at preventing damage. As previously noted, acidizing can cause emulsions, water blocks, and high surface tension problems in carbonates. Sandstones are even more prone to damage during acidizing caused by water and emulsion blocking, high surface tension, oil-wetting, and clay dispersion or flocculation. A surfactant should be employed on all acidizing jobs and should be selected through tests in compliance with API procedure. Because sandstone wells are more susceptible to damage, all fluids and chemicals that are injected or circulated into sandstone wells during well servicing, workover, well completion, and stimulation should be tested for compatibility with formation fluids. If laboratory tests show potential damage caused by fluid circulation or injection into a well, surfactants should be selected through laboratory tests to prevent damage.


ARPO


IDENTIFICATION CODE

PAG

15

OF

34


0 1

If a surfactant is needed, tests must be run to determine the best surfactant for job. 9.8.10

SELECTION OF AN EMULSION BREAKING SURFACTANT.

If an emulsion block is indicated on a completed workover or well completion, emulsion breaking tests should be made using selected surfactants and samples of produced emulsion. If samples of the emulsion are not available, the alternative is to reconstruct, in the laboratory, a similar emulsion using the formation fines, fluids, and chemicals that caused the downhole emulsion. It is usually advisable to run several emulsion breaking tests using different surfactants to select the most effective emulsion breaker. Systems that will not form stable emulsions usually will not require surfactants in the treating solutions. Conversely, if reconstructed systems involved in previous well treatments show stable emulsions, well damage may be due to emulsion blocking of the formation.

9.8.11

REQUIREMENTS FOR WELL TREATING SURFACTANTS.

A surfactant used to prevent or remove damage should: Reduce surface and interfacial tension. Prevent the formation of emulsions and break emulsions previously formed. Water-wet the reservoir rock, considering salinity and pH of water involved. Should not swell, shrink, or disturb formation clays. Maintain surface activity at reservoir conditions. Have solubility in the carrier or treating fluid at reservoir temperature. Some satisfactory surfactants are dispersed in their carrying fluid. Have tolerance for formation brine or produced Many commercial surfactants of all four classes appear to lose much of their surface activity above 50,000 ppm salt. To overcome this difficulty, it is sometimes desirable to pump a preflush of solvent or relatively low salinity water, such as 1% KCI, ahead of the surfactant treatment. The use of a solvent preflush may also reduce water production Immediately following treatment. However, a solvent preflush should not be used in dry gas wells.

9.8.12

WELL STIMULATION WITH SURFACTANTS.

The primary purpose of surfactants in well completion, workover, and well stimulation should be to prevent damage. The real problem in emulsion removal from sandstone formations with surfactants is the near impossibility of getting the surfactant in intimate contact with emulsion droplets in sandstone. Water blocking is relatively easy to treat. The objective is to increase relative permeability to oil and decrease interfacial tension. Emulsion blocks can be treated; however, surfactant stimulation treatments tend to finger, or channel, through a viscous emulsion If most of the emulsion is not broken during surfactant stimulation, the emulsion usually migrates back to the area immediately around the wellbore and restores the blocking condition.


ARPO


IDENTIFICATION CODE

PAG

16

OF

34


0 1

If the damage problem is oil-wetting, this may be alleviated by injecting a strong water-wetting surfactant into the formation. Prior to the surfactant treatment, it may be necessary to clean the tubing, wellbore, and perforations of rust, scale, paraffin, asphaltenes, sand, silt, and other debris.

9.8.12.1

FLUID PLACEMENT.

The surfactant treatment should be planned to insure injection into all permeable zones that are open to the wellbore. In long zones, isolation techniques should be employed to insure that the treated interval does not exceed approximately 50 feet. After squeezing surfactant into the formation at below frac pressure, the well should be shut in for about 24 hours to insure proper surfaction response.

9.8.12.2

PREVENTION OF WELL DAMAGE.

The best method of handling well damage from emulsion or water blocks and oil-wetting is to prevent the damage.

9.9

ACIDIZING.

Acid types, characteristic. Application of additives. Reaction rates, retardation methods. Carbonate acidizing techniques. Sandstone acidizing techniques. Acid may be used to reduce damage near the wellbore in all types of formations. Inorganic, organic, and combinations of these acids, along with surfactants, are used in a variety of well stimulation treatments. In carbonate formations, acid may be used to create linear flow systems by acid fracturing. The two basic types of acidizing are characterised through injection rates and pressures. Injection rates below fracture pressure are termed matrix acidizing, while those above fracture pressure are termed fracture acidizing. Matrix acidizing is applied primarily to remove skin damage caused by drilling, completion, workover or well-killing fluids, and by precipitation of deposits from produced water. Due to the extremely large surface area contacted by acid in a matrix treatment. Removal of severe plugging in sandstone, limestone, or dolomite can result in a very large increase in well productivity. If there is no skin damage, a matrix treatment in limestone or dolomite could stimulate natural production no more than one and one half times. One of the problems in matrix acidizing is that fracture pressure is not always known. Because breakdown or fracture pressure may decrease with a decrease in reservoir pressure, it is frequently necessary to run "breakdown" tests to determine fracture pressure of a specific zone or reservoir. Fracture acidizing is an alternative to hydraulic fracturing and propping in carbonate reservoirs. Undissolved fines can significantly reduce fracture flow capacity if not removed with spent acid. Suspending agents, usually surfactants or polymers, will materially aid in the removal of these fines.


ARPO


IDENTIFICATION CODE

PAG

17

OF

34


0 1

Fracture acidizing has not, normally application in sandstone wells. "Breakdown" of a sandstone well with acid at fracture pressures may break down natural vertical permeability barriers to adjacent unwanted zones. "Breaking-down" with acid may also tend to open channels between the cement and the formation, even though formation fracturing pressure is never reached.

9.9.1

ACIDS USED IN WELL STIMULATION.

The basic types of acid used are: Hydrochloric, Hydrochloric-Hydrofluoric, Acetic, Formic, and Sulfamic. Also, various combinations of these acids are employed in specific applications. Hydrochloric acid (HCI) used in the field is normally 15% by weight HCl; however, acid concentration may vary between 5% and about 35%. The freezing point of 15% acid is -27°F, less than -70°F for 20 to 29% acid, and -36°F for 35% acid. HCl will dissolve limestone, dolomite, and other carbonates. A thousand gallons of 15% HCl will dissolve 1.840 lb. or 10.5 cu ft of zero porosity limestone (CaCO3). This reaction will produce 2,050 lb of calcium chloride (CaCl2), 812 lb of carbon dioxide (CO2) or .600 cu ft of CO2 gas at standard conditions of temperature and pressure, and 333 lb of water. Acetic acid (HAc) is a weakly-ionised, slow-reacting organic acid. The cost of dissolving a given weight of limestone is greater with acetic acid than with HCI. Acetic acid is relatively easy to inhibit against corrosion and can usually be left in contact with tubing or casing for days without danger of serious corrosion. Because of this characteristic, acetic acid is frequently used as a perforating fluid in limestone wells. Other advantages of acetic acid in comparison to HCI are: Acetic acid is naturally sequestered against iron precipitation. It does not cause embrittlement or stress cracking of high strength steels. It will not corrode aluminium. It will not attack Chrome plating up to 200°F. Therefore, acetic acid should be considered when acidizing a well with an alloy pump in the hole. Formic acid is a weakly-ionised, slow reacting organic acid It has somewhat similar properties to acetic acid. However, formic acid is more difficult to inhibit against corrosion at higher temperatures and does not have the widespread acceptance and use of acetic acid. Hydrofluoric acid used in oil, gas, or service wells is normally 3% HF acid plus 12% HCI. It is employed exclusively in sandstone matrix acidizing to dissolve formation clays or clays which have migrated into the formation. Sulfamic acid, a granular-powdered material, reacts about as fast as HCl. The primary advantage of sulfamic acid is that it can be hauled to the location as a dry powder and then mixed with water. Unless sulfamic acid is modified, it will not dissolve iron oxides or other iron scales. Because of its molecular weight, the amount of calcium carbonate dissolved by one pound of sulfamic acid is only about one-third that dissolved by an equal weight of HCI. Acidizing with sulfamic acid is usually much more expensive than with HCI.


ARPO


IDENTIFICATION CODE

PAG

18

OF

34


0 1

Sulfamic acid is not recommended for temperatures above 180°F because it hydrolyses to form sulphuric acid (H2SO4). When H2SO4 reacts with limestone or CaCO3 scale, Calcium sulphate (CaSO4) can be precipitated. 9.9.2

ACID ADDITIVES.

Acidizing can cause a number of well problems. Acid may: Release fines. Create precipitants. Form emulsions. Create sludge. Corrode steel. Additives are available to correct these and a number of other problems. Surfactants should be used on all acid jobs to reduce surface and interfacial tension, to prevent emulsions, to water-wet the formation, and to safeguard against other associated problems. Swabbing and clean-up time after acidizing oil, gas, and service wells can be reduced by lowering surface tension.

9.9.2.1

SUSPENDING AGENTS

Most carbonate formations contain insolubles which can cause blocking in formation pores or fractures if fines released by acid are allowed to settle and bridge. Suspending agents are usually polymers or surfactants. Clean-up after fracture acidizing can be accelerated by use of a suspending agent.

9.9.2.2

SEQUESTERING AGENTS

Act to complex ions of iron and other metallic salts to inhibit precipitation as hydrochloric acid spends. During acidizing if ferric hydroxide is not prevented from precipitating, this insoluble iron compound may be redeposited near the well-bore and cause permanent plugging. Citric acid acts as a cheating agent and is particularly useful when higher iron concentrations are present. Tubular goods are often coated with iron corrosion products which are soluble in HCI. If iron is in the oxidised condition, it will precipitate when HCI spends in the formation and cause plugging of the rock pores. Other sources of iron that could cause plugging in producing, waterflood, and disposal wells are iron sulphide and iron carbonate (Siderite). Acid concentrations used in a well treatment are dependent on the amount of iron that may be dissolved and the formation temperature. HCI concentration may be increased from the normal 15% to as high as 25% where higher concentrations of iron oxide scales are in the well system. A normal acetic acid concentration of 10% is suggested for most applications;. Lactic acid is also an effective sequestering agent but is not usually recommended where the temperature is higher than 200°F.


ARPO


IDENTIFICATION CODE

PAG

19

OF

34


0 1

All sequestered acid solutions require a corrosion inhibitor to minimise acid reaction on tubular goods. Adequate protection to 450°F can be obtained with the correct inhibitor. Well conditions should be thoroughly analysed to determine the most effective sequestered acid solution. Iron precipitation can be prevented for as long as fifteen days. 9.9.2.3

ANTI-SLUDGE AGENTS.

Some crudes, particularly heavy asphaltic crudes, form an insoluble sludge when contacted with acid. The primary ingredients of a sludge are usually asphaltenes; sludges may also contain resins and paraffin waxes, high-molecular weight hydrocarbons, and formation fines or clays. The addition of certain surfactants can prevent the formation of sludge by keeping colloidal material dispersed. Sludge is more of a problem with high strength acids. 9.9.2.4

CORROSION INHIBITORS.

Temporarily slow down the reaction of acid on metal. Corrosion inhibition time varies with temperature, acid concentration, type of steel, and inhibitor concentration. Both organic and inorganic corrosion inhibitors have application in acidizing. Some organic inhibitors are effective up to the 300°F range. Extenders have been developed to increase the effective range to 400°F. Inorganic arsenic inhibitor can be used up to at least 450°F. However, the use of arsenic in oil well treatments has been banned in many areas because even small percentages of arsenic acts as a poison to refinery catalysts. 9.9.2.5

ALCOHOL.

Normally methyl or isopropyl alcohol in concentrations of 5% to 30% by volume of acid, may be mixed with acid to lower surface tension. The use of alcohol in acid may accelerate the rate of well clean-up, particularly in dry gas wells. 9.9.2.6

FLUID LOSS CONTROL AGENTS.

May be required to reduce acid leak-off in fracture acidizing. The preferred method of selecting fluid loss control agents is to run fluid loss tests on cores from the formation to be acidized.

9.9.2.7

TEMPORARY BRIDGING AGENTS.

These materials may be used as temporary bridging agents: Benzoic acid is slowly soluble in water or oil and is available as finely divided particles and as flakes.. Rock salt and Benzoic acid are sometimes used on a 50-50 basis. Ball Sealers are effective. 9.9.3

CARBONATE ACIDIZING.

The objective of acidizing limestone and dolomite wells is to remove damage near the wellbore or create linear flow channels by fracturing. Acid may also be used in sandstone wells to dissolve carbonates in the form of cementing materials and scale. The time required for a specified volume 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


IDENTIFICATION CODE

PAG

20

OF

34


0 1

and concentration of HCI acid spend to about 3.2% in a selected formation under given conditions is defined as Acid Reaction Time. A major problem in fracture acidizing of carbo formations is that acids tend to react too fast with carbonates and spend near the wellbore.

9.9.4

FACTORS CONTROLLING ACID REACTION RATE.

Factors controlling the reaction rate of acid are: Area of contact per unit volume of acid. Formation temperature and pressure. Acid concentration. Acid type. Physical and chemical properties of formation rock. Flow velocity of acid. Reaction time of a given acid is indirectly proportional to the surface area of limestone or dolomite in contact with a given volume of acid. It is very difficult to obtain significant acid penetration before spending during matrix treatments. With a temperature increases, acid spends faster on carbonates, is often necessary increase pumping rate during acid fracturing to place acid effectively before it is spent. An increase in pressure up to 500 psi will increase spending time for HCI. Above this pressure, only a very small increase in spending time can be expected with in creases in pressure. As concentration of HCI increases, acid spending time increases because the higher strength acid dissolves a greater volume of carbonate rock. This reaction releases greater volumes of CaCl2 and CO2 which further retards HCI. Physical and chemical composition of the formation rock is a major factor in determining spending time. Generally, the reaction rate of limestone is more than twice that of dolomite.

9.9.5

RETARDATION OF ACID.

To achieve deeper penetration in fracture acidizing, it is often desirable to retard acid reaction rate. This can be done by emulsifying, gelling, or chemically retarding the acid. Also, HCI can be retarded by adding CaCl2, CO2,. Another approach is to use naturally retarded acetic or formic acid. Emulsification is the most used technique in fracture acidizing to retard reaction rate of HCl on limestone and dolomite within the temperature range of 80°F to 300°F. Emulsified acid usually produces the longest spending time of any retarded acid. It may also serve as a diverting agent between stages of conventional acid. Gelled acid provides minor retardation in the temperature range from 80°F to 200°F Gels usually have high viscosity and low friction loss and provide some fluid loss reduction. Their primary application is as a diverting agent.


ARPO


IDENTIFICATION CODE

PAG

21

OF

34


0 1

Chemically-Retarded Acid—Retardation of HCI is obtained by the addition of a unique surfactant to the acid which causes oil-wet and water-wet spots. Oil, injected ahead of or with the acid, adheres to the oil-wet spots and reduces acid reaction on the oil-wet areas of the fracture faces.

9.9.6

ACIDIZING TECHNIQUES FOR CARBONATE FORMATION.

Carbonate acidizing may be divided into three types: acidizing to remove or bypass formation damage including acid-soluble scales, matrix acidizing, and fracture acidizing. In actual practice, acidizing is usually divided into two categories based on pressure. Acid jobs performed below fracture pressure are called matrix acidizing and are usually aimed at damage removal. Fracture acidizing are usually performed to open new linear flow channels to the wellbore.

9.9.7

MATRIX ACIDIZING CARBONATE FORMATIONS.

The primary purpose of matrix acidizing is to remove or bypass damage due to scale, mud, clay, or hydrocarbon deposits, and to restore natural formation permeability. Matrix treatments are usually performed by soaking, jetting or agitation, or circulation below fracture pressure. Fifteen percent HCI is normally used, with modifications as required. Acetic acid or acetic-HCI mixtures are being employed to a greater extent for specific types of applications. Acetic acid should be considered for temperatures above 250°F because of effectiveness of inhibitors at high temperature.

9.9.7.1

ADDITIVES REQUIRED IN MOST MATRIX ACIDIZING JOBS

A surfactant should be selected to prevent emulsions of spent acid and to lower interfacial and surface tension. A corrosion inhibitor should be selected on the basis of treating temperature and grade of steel tubing and casing. Fluid loss control agents. Diverting agents, or temporary bridging agents may be required to promote uniform injection into long sections. Sequestering agents may be employed to prevent the precipitation of FE(OH)2, which is insoluble in spent acid. Suspending agents are beneficial when considerable insoluble fines are released by acidizing.

9.9.7.2

FRACTURE ACIDIZING CARBONATE FORMATIONS.

Fracturing of limestone or dolomite wells is designed to open linear flow path from the wellbore to some point within the reservoir. In acid fracturing, the objective is to develop permanent flow channels. The alternate to fracture acidizing is to prop open the fracture faces with sand or glass beads. The choice between fracture acidizing and conventional hydraulic fracturing is often a difficult decision. If both systems appear equally feasible to obtain desired fracture flow capacity, then the decision may be based on comparative costs.


ARPO


IDENTIFICATION CODE

PAG

22

OF

34


0 1

The major problems in obtaining fracture flow capacity in fracture acidizing are usually inadequate flow paths and plugging of fracture channel with undissolved fines. The effectiveness of a fracture is a function of both its conductivity and penetration. Created fracture area is proportional to fluid volume and inversely proportional to fluid loss coefficient. Viscous fluids tend to provide wider fractures. Longer fractures are created by higher pumping rates. In some formations, regular or high strength acid fracturing may not provide sustained production increases if large quantities of fines are released in the fracturing by the acid treatment, thus blocking the fracture.

9.9.8

FRACTURE ETCHING IN HOMOGENEOUS CARBONATES.

Many relatively homogeneous limestone or dolomite formations etch uniformly so that inadequate flow capacity is obtained following fracture acidizing. Productivity of fracture-acidized wells may decline rapidly due to the fracture closure in cases where inadequate channels are formed in the fracture faces, or fractures may close over a period of time due to crushing of support pillars as the reservoir pressure declines. To combat the fracture closure problem an high viscosity gel or emulsion, viscous Preflush is pumped ahead of the etching acid. The viscous pad also reduces acid leak-off thus resulting in greater fracture length and width.. One of the initial viscous pads used as a preflush has an apparent viscosity up to 20,000 cp. However, viscosity may be tailored to break back to near I cp after the acid job is complete. Various viscous gels are currently being used as a preflush in fracture acidizing. Chemically Retarded Acid for Selective Etching. The development of a partial oil - wetting and partial water-wetting surfactant acidizing system allows the etching of permanent pillars to hold open the fractures and provide increased fracture flow capacity.

9.9.8.1

ACETIC-HCI MIXTURE FOR MATRIX AND FRACTURE ACIDIZING.

Various acid combinations are employed as indicated by dynamic tests on cores. However, a frequent combination is 15% HCl and 10% glacial acetic acid. Advantages of Acetic-HCI mixture are: 1. For some limestone and dolomite, higher fracture flow capacity is obtained. 2. Acetic acid sequesters iron and prevents formation of ferric hydroxide, an insoluble precipitate. 3. It reduces slugging and emulsification with spent acid. 4. It provides a higher acid strength with a lower corrosivity than an equivalent strength of HCI. 5. Acetic acid with HCI maintains a low pH, thus minimising swelling of clays.


ARPO


IDENTIFICATION CODE

23

OF

34


9.9.8.2

PAG

0 1

FOAMED ACIDIZING.

Foam is becoming widely used for acid fracturing low permeability liquid-sensitive carbonate formations, especially gas wells. Foams employed are a dispersion of gas, normally nitrogen, in acid with a small amount of surfactant foaming agent. Most jobs have been with HCI; however, HCI and organic acid combinations have been employed. Apparent advantages of foamed acid over conventional acid fracturing are: The low fluid loss inherent in foamed acidizing makes more acid available for etching longer fractures. There is less formation damage and wells clean up quicker. The relatively high apparent viscosity of foamed acid results in wider fractures and increases acid spending time because of lower area/volume ratio during acidizing. Higher viscosity improves pumpability. The built-in gas assist of 65 to 85% nitrogen in the spent acid provides rapid cleanup, particularly in low pressure reservoirs. 9.9.8.3

USE OF HIGH STRENGTH HCI ACID.

High strength HCI is any concentration of HCI from about 20% to 35%.

9.9.8.3.1

ADVANTAGES OF HIGH STRENGTH ACID:

Dolomite and some very dense limestones require high strength acid for dissolution. Twenty-eight percent to 33% HCI is usually employed for these types of formation. In fracture acidizing, higher strength acid provides longer spending time, resulting in longer etched fractures. More CO2 is released per gallon of acid and less CO2 is dissolved in spent high strength acid, thus providing more CO2 gas to assist in fracture clean-out after the acid spends.

9.9.8.3.2

DISADVANTAGES OF HIGH STRENGTH HCI ACID:

Corrosion control is difficult and expensive at temperatures above 150°F. High strength steels and high stressed steels are more subject to cracking from embrittlement. Laboratory tests indicate problems with precipitation of significant amounts of insoluble tachyhydrite (CaMg2CI6 12H20) when treating dolomite with HCI concentrations in excess of 20%. Field results indicate severe damage in some wells treated with high strength acid. In relatively dirty carbonate formations where appreciable fines are released by acid treatment, high strength acid will release more fines per volume of acid. This increases the probability of serious plugging of the formation matrix or etched fracture. Sludge and emulsion plugging is considerably more severe with high strength acid. Many damage problems with both high and low strength acid fracturing are overcome by overflushing with a volume of water equal to the volume of acid used in the treatment.


ARPO


IDENTIFICATION CODE

24

OF

34


9.9.9

PAG

0 1

SUMMARY OF USE OF HIGH STRENGTH ACID.

Select the strength of acid required for each job. There is no particular significance in the use of 28% HCI as compared with the use of higher or lower strength acid. Consider the use of high strength acid for acidizing limestone or dolomite along with other available acids from the standpoint of cost, performance, corrosion inhibition, and formation damage. Special care should be exercised in selecting surfactants to prevent the formation of emulsions and sludge. A proper suspending agent as to be select.

9.9.10

SANDSTONE ACIDIZING.

9.9.10.1

PURPOSE AND ACID REACTIONS

The primary reason to acidize sandstone wells is to increase permeability by dissolving clays near the wellbore. Clays may be naturally occurring formation clays or those introduced from drilling, completion, or workover fluids. Hydrofluoric acid (HF) can dissolve calcium carbonate, sand, clay, shale, and feldspars. However, the only reason to use HF acid is to remove clay damage. Treating an undamaged well with HF acid will provide a maximum increase in productivity of about 30%. If the depth of clay damage is only a few inches, HF acid stimulation of a sandstone well can give production increases equal to or greater than the damage ratio. The basic hydrofluoric acid treatment for sand wells is usually 3% HF acid + 12% HCI. SiO2 + 6 HF (Sand)

H2SiF6 + 2H2O (Fluosilicic Acid)

Al2Si4O10(OH)2 + 36 HF ----> 4H2SiF6 + 12H2O + 2H3AIF6 (Clay) (Fluosilicic Acid) (Fluoaluminic Acid ) The acids produced by the reaction HF acid on and clay will react with sodium, potassium, or calcium ions in NaCI, KCI, or CaCI2 in the wellbore in the sand around the wellbore and produce insoluble precipitates. Fluosilicic Acid plus Na+, K+, Ca++ H2SiF6 + 2Na+ H6SiF6 + 2 K+ H2SiF6 + Ca++

→ → →

Na2SiF6 + 2 H+ K2SiF6, + 2 H+ CaSiF6 + 2 H+

Fluoaluminic Acid plus Na+, K+, Ca++ H3A1F6 + 3Na+ + H3AIF6 + 3 K 2H3AIF6 + 3Ca+

→ → →

Na3AIF6 + 3 H+ + 3AIF6 + 3 H Ca3 (AIF6)2 + 6 H+


ARPO


IDENTIFICATION CODE

PAG

25

OF

34


0 1

As may be noted from these reactions, the insoluble precipitates formed are: Na2SiF6, K2SiF6, CaSiF6, Na3AIF6, K3AIF6, and Ca3(AIF6)2. These fluoride precipitates are gelatinous type materials and occupy a large volume of pore space. They also adhere strongly to rock surfaces and reduce well productivity. HCl dissolves very little clay and does not dissolve sand. However, HCl can dissolve carbonates present in sandstone formations. HF acid reacts with limestone and precipitates calcium fluoride, an insoluble fine white powder. The total reaction is: CaCO3 + 2HF

→

CaF2 + H2O + CO2

To avoid CaF2 precipitation in sandstone acidizing, a preflush of HCI is used to dissolve the limestone and prevent calcium ions from contacting HF acid. Sandstone formations having more than 20% solubility in HCI should normally be treated with HCI only. The ammonium ion does not form insoluble compounds with HF acid reaction products. Therefore, ammonium chloride solutions may be used as a preflush or afterflush in HF acid treatments.

9.9.11

PLANNING HF ACID STIMULATION.

The objective of most HF acidizing treatments is to eliminate damage around the wellbore due to: Clay invasion of pores from drilling mud and well circulating or workover fluids containing a small quantity of clay. Emulsion blocking around the wellbore may also be removed along with clay blocking. A matrix type treatment with injection below fracture pressure should be used. In planning an HF acid treatment to remove clay damage, the primary factors to be considered are the depth of damage and the weight percent of clay naturally occurring in the formation plus the weight of clay that has been forced into the formation pores near the wellbore from drilling or workover fluids. It may be assumed that reaction of live HF acid on clay is essentially instantaneous. To achieve stimulation, the treatment should be designed to meet these requirements: Dissolve clays and mud solids near the wellbore. Prevent the precipitation of insolubles in the formation. Prevent the spent acid from emulsifying. Leave the sand and remaining fines in a water-wet condition.

9.9.12

ADDITIVES FOR SANDSTONE ACIDIZING

Surfactants should be employed throughout the treatment to prevent emulsions, to lower surface and interfacial tension, and to water-wet sand and clay. Corrosion inhibitiors should be selected for compatibility with surfactants employed.


ARPO


IDENTIFICATION CODE

PAG

26

OF

34


0 1

Mutual solvents, materials at least partially soluble in both water and oil, have a special role in sandstone acidizing. The mutual solvent initially employed in sandstone acidizing was ethylene glycol monobutylether (EGMBE) and is sold under various trade names such as: Musol by Halliburton; U-66 by Dowell Halliburton now offers a new mutual solvent, a modified glycol ether, Musol A. which is both a mutual solvent and a good water-wetting surfactant. Diverting Agents Most of the diverting agents used in acidizing limestone are applicable. However. rock salt (NaCl) cannot be used with HF acid

9.9.13

CLAY STABILISATION.

As noted previously. an HF acid treatment is normally preceded by a volume of HCI to dissolve carbonates. However, the action of HCI in the formation can dislodge clays and other fines. If all of these released fines are not dissolved by HF acid, they may migrate toward the wellbore when the well is put back on production. Bridging at flow restrictions in the pores of the sand can occur and cause production declines in a relatively short time. The addition of certain cationic organic polymers to the acid and afterflush can minimise fines migration and subsequent pore plugging.

9.9.13.1

WELL PREPARATION PRIOR TO ACIDIZING SANDSTONE FORMATIONS.

Clean out debris from wellbore. Remove any paraffin or asphalt in tubing or wellbore. Remove any acid-soluble and acid-insoluble scales from tubing, wellbore, and perforations. Reperforate if necessary to insure entry of acid into desired intervals.

9.9.13.2

THE ROLE OF MUTUAL SOLVENTS IN ACIDIZING SANDSTONE.

Gidleyl° in 1970 reported many successful sandstone acidizing jobs using a mutual solvent, ethylene glycol monobutyl ether, (EGMBE). However, the exact function of mutual solvents in sandstone acidizing remained unclear. The addition of 10% by volume of various mutual solvents to the solution of HCl indicated that mutual solvents preferentially adsorb on silica, thereby allowing the surfactant to be available for lowering surface tension. All of the tests performed in the laboratory indicated that preferential adsorption of mutual solvents on the sand and clay prevented the cationic emulsion breaker and cationic corrosion inhibitor from being adsorbed on the clay. The cationic surfactants were then available to maintain low surface tension, prevent emulsions, and provide corrosion inhibition. Mutual solvents can effectively prevent the adsorption of emulsion breakers and cationic corrosion inhibitors on sand and clay. Mutual solvents should be used with either HCI or HF-HCl treatments when cationic emulsion breakers are used. Mutual solvents should be used on acidizing of sandstone along with suitable surfactants, unless the specific surfactant does not appreciably adsorb on sandstone or clay.


ARPO


IDENTIFICATION CODE

PAG

27

OF

34


0 1

Mutual solvents can solubilize surfactants in acid thus increasing the effectiveness of surfactants. If mutual solvents are used in HCl or HF-HCI sandstone acidizing, the mutual solvent should always be in the preflush along with a suitable surfactant.

9.9.14

PREFLUSH FOR SANDSTONE ACIDIZING OF OIL WELLS.

A preflush of HCI should normally be employed ahead of HF acid to insure that carbonates are removed from the wellbore and from the formation rock adjacent to the wellbore. Because most sandstones contain some carbonates as cementing material or as discrete particles, it appears advisable to use an HCI preflush on essentially all jobs, with the percent and volume of HCI depending on quantity of carbonates to be dissolved. 5% to 15% HCI plus surfactant (usually anionic-non-ionic), corrosion inhibitor, and 5% to 10% mutual solvent (optional) is normally used as Preflush

9.9.15

HF-HCI ACID TREATMENT FOR OIL WELLS.

Chemicals used: 3% HF + 12% HCl, surfactant, corrosion inhibitor, and 5 to 10% mutual solvent (optional). Prepare acid with fresh water only. Higher strength than 3% should usually be avoided to minimise formation collapse.

9.9.15.1

EFFECT OF HF ACID ON SANDSTONE FORMATION

HF acid dissolves feldspar, naturally occurring formation clays, and clays deposited from drilling and completion fluids. It also reacts slowly on formation sand. HF acid reacts rapidly on carbonates to produce an insoluble precipitate, calcium fluoride. Complete dissolution of cementing materials, normally silica, carbonates, or clays, between sand grains will result in disintegration of the formation matrix.

9.9.15.2

AFTERFLUSH FOR OIL WELL TREATMENTS.

Inject about 25 gal afterflush per foot of sand. Afterflush may be 5% to 10% HCl, 2% Ammonium Chloride solution, clean filtered kerosene, diesel oil, or crude oil. All fluid should contain about 0.1% water-wetting non-emulsifying surfactant. The purpose of the afterflush is to act as a buffer between the HF acid and the pump down fluid. Sufficient afterflush should be used to thoroughly displace the HF acid into the formation. HF acid spends very rapidly. Within one hour after afterflush is injected, swabbing, pumping, or gas lifting of the spent acid should be initiated. This will reduce the possibility of formation damage due to emulsion and insoluble precipitates.

9.9.16

STIMULATION OF GAS WELLS, GAS INJECTION WELLS, AND WATER INJECTION WELLS

Treatment should follow the oil well stimulation procedure with these modifications: 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


IDENTIFICATION CODE

PAG

28

OF

34


0 1

HCl should normally be used in the preflush or afterflush. Oil should not be employed in the preflush or afterflush. Gas wells should be swabbed or flowed within one hour after HF acid treatment. It is not always necessary to swab water and gas injection wells following an HF acid job. Within one hour after treatment, regular injection into water or gas injection wells may be resumed.

9.9.17

IN-SITU HF GENERATING SYSTEM (SGMA)20.

Shell's SGMA, an in-situ acid generating system was developed to allow cleanup of deep damage due to clays in sandstone formations. SGMA involves pumping into the formation an aqueous solution of ammonium fluoride and an organic ester such as methyl formate. With time the ester hydrolyses to produce an organic acid such as formic acid. The organic acid reacts with NH4F to form HF acid, which rapidly dissolves clay or siliceous fines present in the pores. The system is applicable from 130° to 200°F. Wells should be shut in for a long period of time following treatment, with required shut-in time decreasing with increased temperature. Wells are brought back into production very slowly by gradually increasing choke size over a period of several weeks.

9.9.18

CLAY ACID.

Clay acid (fluoboric acid) was developed by Dowell as a retarded acid system for use on sandstone formations. It is designed to reduce deep damage attributable to migration of clays and fines. The fluoboric acid not only dissolves clays, but also immobilises clays and fines that are contacted but not dissolved. Fluoboric acid hydrolyses to generate hydrofluoric acid (HF and hydroxyl Fluoboric acid) according to the following equilibrium equation: HBF4 + HOH = HBF30H + HF Although the hydrolysis proceeds rapidly, the equilibrium allows only about 5% of the available HF to exist at any one time. The slower reaction rate allows the fluoboric acid to penetrate a greater distance into the formation before spending. After the available HF has spent, the remaining hydroxyl fluoboric acid (HBF30H) slowly reacts with the clays "fusing" (or bonding) them and other fines to one another and to the sand grains. As a result, fines are stabilised against dispersion by incompatible fluids and mechanical dislodgement. The "fusion'' reaction is not well-defined, but is attributed to the slow secondary reaction between hydroxyfluoboric acid and the clays. Wells treated with clay acid showed little, if any, decline even after six to eight months; wells after mud acid treatment had declined severely in less than six months.

9.9.19

POTENTIAL SAFETY HAZARD IN ACIDIZING.

Hydrogen sulphide, a poison gas, may be produced from the reaction of acid on sulphide scale. Hydrogen sulphide smells like rotten eggs at low concentrations. High concentrations can paralyse


ARPO


IDENTIFICATION CODE

PAG

29

OF

34


0 1

the olfactory nerves and prevent detection by smell of dangerous gas concentrations. High concentrations can also paralyse other nerves in the respiratory system. Arsenic inhibitors should generally be avoided because of their toxicity and the environmental protection problems. Acetic anhydride, used in formulating acetic acid, produces vapours which are very irritating, and direct contact will cause severe burns. Dust from ammonium bifluoride used in making HF acid is very irritating. Contact with the dust or active HF acid should be avoided. Most additives used in acid are toxic to varying degrees. Chemicals contacting the skin should be removed immediately by washing with soap and water.

9.10

SCALE DEPOSITION, REMOVAL, AND PREVENTION.

Causes of scale deposition. Prediction of scaling tendency. Identification of scale. Scale removal. Scale-prevention methods.

9.10.1

INTRODUCTION.

Scale is deposited in formation matrix and fractures, wellbore, downhole pumps, tubing, casing, flowlines. Scale deposits usually form as a result of crystallisation and precipitation of minerals from water. The direct cause of scaling is frequently pressure drop, temperature change, mixing of two incompatible waters, or exceeding the solubility product. Scale sometimes limits or blocks oil and gas production. The most common oil field scale deposits are calcium carbonate (CaC03), gypsum (CaS04 2H20), barium sulphate (BaSO4) and sodium chloride (NaCI). A less common deposit is strontium sulphate (SrS04). Scale deposited slowly may be very hard and dense, and may be difficult to remove with acid or father chemicals.

9.10.2

LOSS OF PROFIT.

It is estimated that a majority of the 700,000 oil, gas, and service wells in the U.S. have appreciably reduced productivity or injectivity because of scale deposited in the wellbore, perforations, the formation matrix, or in formation fractures. Scale causes a large number of costly pulling jobs.

9.10.3

CAUSES OF SCALE DEPOSITION.

Primary factors affecting scale precipitation, deposition, and crystal growth are: supersaturation. Mingling of two unlike waters having incompatible compounds in solution. Change of temperature and pressure on solution.


ARPO


IDENTIFICATION CODE

PAG

30

OF

34


0 1

Evaporation (affects concentration). Agitation. Contact time. pH.

9.10.3.1

TENDENCY TO SCALE—CAC03

In oil wells, calcium carbonate precipitation is usually caused by pressure drop releasing CO2 from bicarbonate ions (HCO3-). When CO2 is released from solution, the pH increases, the solubility of dissolved carbonates decreases, and the more soluble bicarbonates are converted to less soluble carbonates. Water Soluble Scale. Chemical Name

Chemical Formula

Mineral name

Sodium Chloride

NaCI

Halite

Chemical name

Chemical Formula

Mineral name

Calcium Carbonate Iron Carbonate Iron Sulphide Iron Oxide Iron Oxide Magnesium Hydroxide

CaC03 FeCO3 FeS Fe203 Fe304 Mg(OH)2

Calcite Siderite Trolite Hematite Magnetite Brucite

Chemical name

Chemical Formula

Mineral name

Calcium Sulphate Calcium Sulphate Barium Sulphate Strontium Sulphate

CaS04 CaSO4 2H20 BaSO4 SrS04

Anhydrite Gypsum Barite Celestite

Acid Soluble Scale.

Acid Insoluble Scale.

Scale precipitation also varies with calcium ion concentration (common ion effect—such as from CaCI2), alkalinity of water (concentration of bicarbonate ion), temperature, total salt concentration contact time, and degree of agitation:


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Scaling will increase with increased temperature. Scaling increases with an increase in pH. Scaling increases and becomes harder with in creased contact time. Scaling increases with increase in turbulence. Mixing of two incompatible waters will cause precipitation of CaC03 scale. 9.10.3.2

TENDENCY TO SCALE—GYPSUM (CAS04 2H20) OR ANHYDRITE (CAS04).

The most common form of calcium sulphate scale deposited downhole is hydrous calcium sulphate or gypsum (CaS04 2H20). A reduction in pressure decreases solubility and causes scaling. Mixing of two waters, one containing calcium ions and the other containing sulphate ions, often causes gyp scaling, particularly in waterflooding. Agitation increases scaling tendency. Evaporation of water due to evolution of free gas near or in the wellbore may cause supersaturation and gyp scaling. A change in temperature will change the solubility of calcium sulphate or gyp and the tendency to precipitate.

9.10.3.3

TENDENCY TO SCALE—BASO4 AND SRS04.

For a given NaCl concentration, BaSO4 scaling increases with decreases in temperature as a result of decreasing BaSO4 solubility. Both BaSO4 and SrSO4 scales are usually caused by mingling of two unlike waters, one containing soluble salts of barium or strontium and the other containing sulphate ions. Pressure drop may decrease the solubility of BaSO4 in a given solution and cause scaling. 9.10.3.4

TENDENCY TO SCALE—NACI.

Precipitation of sodium chloride is normally caused by supersaturating usually due to evaporation or decreases in temperature. 9.10.3.5

TENDENCY TO SCALE—IRON SCALES.

Iron scales are frequently the result of corrosion products such as various iron oxides and iron sulphide. Sulphate-reducing bacteria can be a source of hydrogen sulphide, which then reacts with iron in solution or with steel surfaces to form iron sulphide. If oxygen is introduced to a system, it can react with iron to form a precipitate and with steel surfaces to form an oxide coating.


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PREDICTION AND IDENTIFICATION OF SCALE.

Techniques discussed under "Tendency to Scale" are very helpful in predicting various types of scale. The Stiff and Davis method has been used for many years to show scaling tendencies. However, the age and method of collecting samples may have a bearing on the water analysis values obtained. For example, an aged sample of water may show different values than a fresh sample for pH, bicarbonate content, and CO2. The best procedure is to measure water properties immediately after sampling. Analysis of produced brine is an aid in predicting scaling in surface facilities, but may not provide a reliable basis to estimate downhole scaling in producing wells. Downhole deposition of scale, frequently due to release of CO2 from bicarbonate ions in water as pressure declines tends to cause an error in predicting scaling tendencies from produced brine. If bottomhole pressure is near original, bottomhole samples brought to the laboratory under subsurface pressure and temperature conditions may provide reliable information on both downhole and surface scaling tendencies under original reservoir conditions.

9.10.5

IDENTIFICATION OF SCALE.

X-ray diffraction is the most used method for scale identification. Each crystalline chemical compound in the scale diffracts X-rays in a characteristic manner. Chemical analysis may also be used for scale identification, Samples of scale are decomposed and then dissolved in chemical solution. Chemical elements are then analysed by standard techniques of titration or precipitation.

9.10.6

SCALE REMOVAL.

Scale is classified by methods of removal. Chemically inert scales are not soluble in chemicals. Chemically reactive scales may be classified as (a) water soluble, (b) acid soluble, and (c) soluble in chemicals other than water or acid.

9.10.6.1

MECHANICAL METHODS.

Mechanical methods such as string shot, sonic tools, drilling, or reaming have been used to remove both soluble and insoluble scales from tubing, casing, or open hole.

9.10.6.2

CHEMICAL REMOVAL.

9.10.6.3

WATER-SOLUBLE SCALE.

The most common water-soluble scale is sodium chloride which can be readily dissolved with relatively fresh water.


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ACID-SOLUBLE SCALE

The most prevalent of all scale compounds, calcium carbonate (CaCO3), is acid-soluble. Hydrochloric acid (HCl) or Acetic acid can be used to remove calcium carbonate. Acid-soluble scales also include iron carbonate (FeCO3), iron sulphide (FeS), and iron oxides (Fe203). HCl plus a sequestering agent is normally used to remove iron scale. A 10% solution of Acetic acid may be used to remove iron scales without an additional sequestering agent; however, Acetic acid is much slower acting than HCl. Scales are frequently coated with hydrocarbons, thus making it difficult for acid to contact and dissolve the scales. Surfactants can be added to all types of acid solutions to develop a better acidto-scale contact.

9.10.6.5

ACID-LNSOLUBLE SCALES

The only acid-insoluble scale which is chemically reactive is calcium sulphate or gypsum. Calcium sulphate, though not reactive in acid, can be treated with chemical solutions which can convert calcium sulphate to an acid soluble compound, such as CaCO3 or Ca(OH)2. Scale-removal procedure if waxes, iron carbonate and gyp are present is: Degrease with a solvent such as kerosene, or xylene, plus a surfactant. Remove iron scales with a sequestered acid. convert gyp scales to CaC03 or Ca(OH)2. Remove converted CaCO3 scale with HCI or Acetic acid. Dissolve Ca(OH)2 with water or weak acid. Compounds such as EDTA (Ethylenediamine-tetracetic acid) and DTPA (diethylenetriaminepentaacetic acid) can dissolve gyp without the necessity of conversion to CaCO3 or Ca(OH)2. 9.10.6.6

CHEMICALLY INERT SCALES

The most common chemically inert scales are barium sulphate (BaSO4) and strontium sulphate (SrSO4). These scales can be removed by mechanical methods, or bypassing by reperforating. The best approach is to prevent their deposition.

9.10.7

SCALE PREVENTION.

Inhibition of Scale Precipitation by Inorganic Polyphosphates. Inhibition of Scale with Polyorganic Acid. Inhibition of Scale with Organic Phosphates and Phosphonates. Inhibiting Scale with Polymers CaC03 Scale Prevention by Pressure Maintenance If calcium carbonate scale can be predicted as a result of drop in reservoir pressure, pressure maintenance should be considered as a means of reducing scaling.


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CONCLUSIONS

Steps to be taken in solving scale problems are: Identify the scale and the reason for its deposition. Remove deposit by chemical or mechanical means. In perforated completions, it may be more satisfactory to bypass scaled perforations by reperforating.


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CHAPTER 10 - SAND CONTROL & GRAVEL PACK DISTRIBUTION LIST TEAP STAP – Archive





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REVISIONS

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



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INDEX 10. SAND CONTROL: GRAVEL PACK ..............................................................................................3 10.1 INTRODUCTION .....................................................................................................................3 10.2 REASONS FOR SAND CONTROL .........................................................................................3 10.3 HOW OR WHEN TO DECIDE THE SAND CONTROL NEED .................................................3 10.4 SAND CONTROL MECHANISM..............................................................................................4 10.5 MECHANICAL METHOD OF SAND CONTROL......................................................................5 10.6 DEVELOPMENT OF DESIGN CRITERIA ...............................................................................5 10.7 SCREEN SLOT SIZE. .............................................................................................................6 10.8 GRAVEL SIZE TO CONTROL SAND......................................................................................6 10.9 THICKNESS OF THE GRAVEL PACK. ..................................................................................6 10.9.1 FLUCTUATING FLOW RATE ........................................................................................6 10.9.2 MIXING OF GRAVEL WITH SAND. ...............................................................................7 10.10 PRACTICAL CONSIDERATION IN GRAVEL PACKING.......................................................7 10.10.1 GRAVEL SELECTION .................................................................................................7 10.11 QUALITY CONTROL.............................................................................................................8 10.11.1 SCREENS AND LINER CONSIDERATIONS. ..............................................................8 10.11.2 GRAVEL-PACKING FLUIDS........................................................................................8 10.12 FLUID DENSITY....................................................................................................................9 10.12.1 VISCOUS WATER FLUIDS. ........................................................................................9 10.13 INSIDE CASING GRAVEL PACK TECNIQUE.......................................................................9 10.14 OPEN HOLE GRAVEL PACK TECHNIQUE. ......................................................................10 10.15 PUTTING WELL ON PRODUCTION IS A CRITICAL POINT ..............................................10 10.15.1 LIFE OF THE GRAVEL PACK ...................................................................................10 10.15.2 USE OF SCREEN OR LINER WITHOUT GRAVEL ...................................................11 10.16 RESIN CONSOLIDATION METHODS OF SAND CONTROL. ............................................11 10.16.1 THEORY OF RESIN CONSOLIDATION. ...................................................................11 10.16.2 RESIN CONSOLIDATION ADVANTAGES.................................................................11 10.16.3 RESIN SAND-PACK SYSTEM. ..................................................................................12 10.16.4 RESIN PROCESSES. ................................................................................................12 10.17 COMPARISON OF SAND CONTROL METHODS SUMMARY............................................13


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10.

SAND CONTROL: GRAVEL PACK

10.1

INTRODUCTION

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Sand production associated with oil and gas wells is one of the oldest problems facing the petroleum industry. This problem occurs throughout the world in the younger Tertial Age reservoir, particulary in the Miocene and Pliocene Age sands. Typically, these formations are weakly consolidated by argillaceous cementing materials, interaction of intergranular friction and “in situ” stresses, capillary forces and by viscosity of the fluids in place. Geographically, unconsolidated or poorly consolidated sands are a significant problem in formations at shallow depth in the Gulf Coast areas of Texas and Louisiana, in California, Canada, Mexico, Venezuela, Trinidad, North Sea, Germany, Bahrain, Nigeria, Congo, Indonesia and Italy. Howevar, some completely unconsolidated formations have also been found in the edge of the Mississipi delta at 6000 metres. The purpose of this chapter is to: • Define the technology and scope of sand control by describing common problems, contributing factors, available methods and selection criteria. • Present applications and selection criteria for chemical formation consolidation. Introduce gravel packing concepts such as gravel and screen selection, perforations, hole and formation preparation, placement techniques, viscous slurry and circulation packing, including applications for both cased and open hole job.

10.2

REASONS FOR SAND CONTROL

The sand control is required when sand appears in the produced hydrocarbons. This generates problems like: • Down hole casing or slotted liner failure due to erosion. • Production stopping due to sand bridges formation inside casing or tubing. • Erosion on production equipment, i.e., tubing, safety valve, landing nipple, well head, surface equipment, expecially near cross-sections changes or directions, etc.... • Production loss. • Cost disposal problems due to handling of the produced sand. In case of gas wells the sand production can be monitored by a “Sonic Sand Device”, through an electronic probe installed in a surface flow line. A continuous monitoring can allow correcitve actions to be taken before exessive erosion damage on surface or down hole equipment has occured.

10.3

HOW OR WHEN TO DECIDE THE SAND CONTROL NEED

An actual common idea is that the sand control should be actuated before production starting when, through the initial engineering study or a well test after well’s drilling, a sure sand production can be predicted.


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Formation grains are stabilized by compressive forces due to the wheight of the overburden, by capillary forces, and by cementation between sand grains. Causes of sand production are related to: • Drag forces of flowing fluid which increase with higher flow rate and higher fluid viscosity. • Reduction in formation strength which is associated with water production due to dissolving or dispersion of cementing material or a reduction in capillary forces withwith increasing water saturation. • Reduced permeability to oil, due to increased saturation, which increases pressure drawdown for a given oil production rate. • Declining reservoir pressure which may disturb cementation between grains.

10.4

SAND CONTROL MECHANISM

Basiclly sand production can be controlled by three mechanism: 1. Reducing drag forces. 2. Bridging sand mechanically. 3. Increasing formation strength. Reduction drag or frictional forces is often the most effective and simplest means of controlling sand. Fluid production rate causing sand movement must be considered as a rate-per-unit area of permeable formation. The drag force is decrased by increasing the flow area which is obtained by: • • • •

Provide clean, large perforations through the existing productions section. Increase perforation density. Opening increased length of section. Creating a conductive path some distance into the reservoir by means of a packed fracture.

Good completion practice, use of clean fluids, and careful selection of perforating charges and perforating conditions can effectively reduce serious sand control problems. The drag force is decrased by : Restricting the production rate . The well could be produced with the maximum rate below the critical rate where sand production becomes “execcive”: “Excessive” sand production could cause: • Well sand up with conseguent clean out cost and possible formation damage. • Cut out of well head or surface equipment with possibilòity of physical danger or disaster. • Casing collapse, due to slumping of higher formation into the zone weakened by sand roduction.


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A careful monitoring of sand pruduction versus production rate allow the possibility to extablish, for untreated wells, the maximum production rate without excessive sand production is proportional with the length of the producing interval. Maximum production rate without excessive sand appears to be related to three equally important factors: Productivity index . Length of the completion zone. Formation strength or “drawdown factor” The “drawdown factor “ related with the sonic transit time. Is possible with the the value of sonic transit time and the productivity index together with the zone length to estimate the maximum production rate before sand problems. In order to monitor the sand production is possible to use surface devises like: • Erosion probe. • Surface sonic device for temporary installation in a flow line to “hear” sand inpinging on the detector.

10.5

MECHANICAL METHOD OF SAND CONTROL.

Mechanical methods of sand control involve use of gravel to hold formation sand in place ( with the screen to retain the gravel) , or a screen to retain the formation sand (with no gravel). The basic problem is how to control formation sand without an excessive reduction in well productivity. Basic design parameters include: • Optimum gravel size in relation to formation sand size. • Optimum screen slot width to retain the gravel,or if no gravel, the formation sand. • An effective placement tecnique is , perhaps most important.

10.6

DEVELOPMENT OF DESIGN CRITERIA

The first step is getting representative samples. Sand-grain size distribution often varies through a particular sand body and certaily from one genetic zone to another. Thus for representative measurements a number of samples are needed. Full diameter cores are best; rubber sleeve core barrels may be needed for recovery. Side wall cores are good. Samples for perforation washing or back surging are acceptable. Produced or bailed samples are better than nothing. Sieve analisys provides grain size distribution on percentile basis and on the basis of sieve analisys the gravel size is chosen.


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SCREEN SLOT SIZE.

Slot width should be as large as possible to retain sand grains but not restrict the fluid flow and intestitial fines. Coberly established the upper limit on slot width of not more than twice the 10 percentile sand size in order to bridge effectively. This allows some movement of grains through the slot before bridges form. Changes in flow rate may cause bridges to fail. For retaining formation sands where grains are more difficult to bridge and/or where frequent changes in flow velocity occur experience dictates use of slot width equal to (not twice) the ten percentile sand diameter. since it is imperative that all gravel be tightly placed and retained, screen slot width for a gravel pack must be smaller than the smallest gravel grain size.

10.8

GRAVEL SIZE TO CONTROL SAND.

The first approach to grain size determination was to establish the gravel sand size considering only the problem of preventing movement of sand into the Wellbore, and not the permeability of the gravel pack.This led to large gravel-sand ratio. Later it became clear that for maximum productivity, the formation sand must be stopped at the outer face of the gravel pack. If sand bridges occur within the gravel pack itself, permeability is significantly reduced. This thinking started the current Industry trend toward the lower gravel-sand ratio. The effect of G-S ratio on gravel pack permeability is best shown by lab work by Saucier. Most laboratory work shows ideally that gravel-sand size ratios should be in the range of 5 to 6. In a tight pack with a G-S ratio of 6 implies that the reference sand grain is too large to move through the pores of the gravel pack. Withn a “loose pack” trhe reference sand grain can move through the pores between gravel grains before the bridging will occur.

10.9

THICKNESS OF THE GRAVEL PACK.

In lab experiment a gravel pack thickness of four or five gravel diameters will control sand.In practice much thicker packs are necessary to control sand. With the practical problems of placing gravel a 3” thickness is a minimum. This means that open hole must be underreamed to provide 3“ on the radius between the screen and the formation.In perforated casing gravel must be placed through the perforation tunnel outside the casing. Thicke gravel packs permit higher production rate. 10.9.1

FLUCTUATING FLOW RATE

Once the bridging effect is extablished for a good sand control is important that this equilibrium is not disturbed. A sharp increase or a sharp decrease of flow rate can cause a temporary increase of sand production. Tests were performed indicating that rate changes may be more significant that the magnitude of flow rate.Apparently for a given flow condition, sand bridges form are stable for existing geometrics and hydrodynamics forces. As fluid forces are altered, bridges breakdown, and more sand is produced until new bridges form under the new condition. 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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MIXING OF GRAVEL WITH SAND.

The mixing of high permeability gravel with formation sand, as may occur during placement of gravel, will significantly reduce the permeability of the resulting sand gravel-misture. Fines in the gravel will also decrease the gravel pack permeability. Therefore the following rule-of thumb are suggested: • Use as large gravel as possible but formation sand must be stopped at the outer edge of the gravel pack. • Gravel size (at 40 percentile point) shoud be 6 times the 40 percentile point of the sand analysis curve. For low velocities and uniform sands, the 10 percentile points can be used for sand and gravel reference. • Where sand grain analysis vary within the formation, pay more attention to the smaller grain size, particulaly with higher flow velocity, more non-uniform sand, fluctuation flow rate, and high gas oil ratios. • Pack the gravel tightly • Pack thickness should be at least 3 inches. • Avoid the mixing with formation sand in placement.

10.10

PRACTICAL CONSIDERATION IN GRAVEL PACKING.

The keys to succesful gravel packing are: • Selecting gravel of the proper size and quality. • Placing the gravel without contamination as tightly as possible and holding it in place for the life of the well. The objective is to control the sand production without excessive loss of productivity. An open hole gravel pack provides the maximum productivity because a much greater area is open to flow; therefore an open hole gravel pack should always be selected when the open hole is compatible with other completion considerations. Control of extraneous water or gas in the subsequent life of the well may, however, rule in favor of the perforated casing or inside casing gravel pack. 10.10.1

GRAVEL SELECTION

Gravel size is often specified in terms of U.S. mesh. If sonic travel time show a particular zone to be weak, then obviously, gravel should be sized to control this zone. If no data are available, gravel should be sized to control the smaller formation sizes.


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QUALITY CONTROL

Suitability of a particular gravel depends on: • Roundness and sphericity. Flat or angular grains should be avoided. • Grain strength: depends on depth and formation stress level same as frac sand. • Acid solubility. acid solubility should be checked. Gravel should be greater than 985 pure silica. Feldspar content should be nil since feldspar is completely soluble in HF acid. • Uniformity: the closer the limits on gravel grain size variation, the grater will be the permeability. Clay size material: presence of clay or silt can determined by adding clear water to a bottle partially full of gravel. After vigorous shaking, turbidity should be less than 1%.

10.11.1

SCREENS AND LINER CONSIDERATIONS.

Wire-wrapped screens are the most widely used for gravel pack application and have the advantage of more erosion and corrosion resistant material. Flushed joint connections should be used inside casing to prevent bridging of gravel. The liner screen must be centralized inside casing or in open hole. A liner packer is required to prevent flow fluids and gravel upward around the outside of the liner.

10.11.2

GRAVEL-PACKING FLUIDS.

One of the most important considerations in gravel packing is to pay a proper attention to the gravel packing fluid. Keeping in mind that: • • • •

Low viscosity fluid may provide tighter gravel placement. Fluids must be tailored to minimize clay wettability problems. Fluids must be clean or filtered through two micron filters. Gravel concentration of 1/2” to 1 lb/gal can be carried with pump rates up to 5 bbl/min.

• It is absolutely necessary to avoid that a solid-particle filter cake will remain on the formation face in open hole gravel pack or in the perforation or cavity on inside casing gravel pack. • Clean fluid must be stored in clean tanks and must be used to displace “dirty” fluids from the well. • For underreaming operations, a desilter shoud be used in conjunctin with the filter. • In order to avoid fluid losses a minimum hydrostatic overload above the formation should be used. • Viscosity and fluid loss control should be avoided in order to minimize the formation damage. • In very uncemented sand , sloughing may occur with no-solids fluids. This is controlled by building a fluid loss particle bridge on the face of the formation against which hydrostatic pressure can be applied.A reasonable approach where fluid loss control must be applied is to use acid soluble (CaCO3 ) held in suspension with degradable material (HEC polimer). Oil soluble particles could be also applied. 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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FLUID DENSITY

If weights greater than 10 Lb/ft are required the following fluids could be applied. • CaCl2 can be prepared weighing up to 11.5 lb/gal. • CaBr2 can be prepared weighing up to 15 lb/gal. • ZnBr2 can be prepared weighing up to 19.2 lb/gal. 10.12.1

VISCOUS WATER FLUIDS.

Can permit extreme gravel concentration (15 lbs/gal of liquid or 9 lbs/gal of slurry). Thus the gravel pack is placed more quickly and with less loss of fluid into formation. Two problems must be considered once viscous fluids are used: • The type and concentration of viscosity breaker must be determined depending on formation temperature. • The sump volume below the screnn must be minimized to reduce further settling of the gravel, thereby loosening the pack, after the viscosity has broken.

10.13

INSIDE CASING GRAVEL PACK TECNIQUE.

Perforations are the basic problem. Everithing must be aimed at obtaining large diameter clean perforations.Big hole gun are used to obtain a perforation tunnel of 3/4” to 7/8”. High density shot charges are used 6-8 spf especially for high rate production areas. In order to have a clean perforations a back surge tecnique followed by a perforation washing tool run was used in the past. A small pill of HF-HCl was pumped in the past to remove metallic charges before gravel pack placement. The back surge-perforation washing tecnique followed by HF-HCl pill have been replaced by Tubing Conveyied Perforations. Peforation tunnels must be filled with gravel or it will be plugged by sand. Increasing the perforation hole area or the permeability of the filling material is a primary approach for reducing pressure drop for a given flow rate through a single perforation. The pressure pack method attempts to carry gravel through open perforations to fill a possible "cavity" behind the pipe and the perforation tunnel. During placement, fluid carries gravel down the annulus between the inside of the casing and outside the screen or slotted liner, with the gravel being deposited, and the fluid moving through the slots to the bottom of the liner assembly, and back up through the wash pipe. Periodically, return flow into the wash pipe is restricted, forcing fluid through the perforations and into the formation at below fracture pressure, hopefully carrying gravel into the perforation tunnels. The wash down technique has application in short low-productivity zones (10-15 ft). Gravel is placed through open ended tubing, then a screen is washed down through the gravel. Circulation is stopped, the gravel allowed to settle back around the liner, and a liner packer is set. Dual Zone Gravel Pack Equipment is available for gravel packing two zones in a dual completion, maintaining pressure separation between zones. Equipment and procedures were widely applied to complete all the wells for Giovanna field development in Italy.


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For a further sand control is possible to run through tubing pre-pack screens and set them into tail pipe. Pre pack screen are able to withstand sand production but they are often cut by the sand itself.

10.14

OPEN HOLE GRAVEL PACK TECHNIQUE.

Due to the much higher area open to flow of produced fluids entering the well bore, the open hole gravel pack has an inherent margin for error (i.e., less clean fluids, slightly larger gravel, etc.). The open hole section should be underreamed 4 to 6 inches on the diameter to provide needed thickness of gravel, and to remove drilled solids and mud cake from the face of the open hole. Underreaming fluids must be cleaned as the operation proceeds. Equipment and placement technique are similar to inside casing, using the crossover reverse circulation method. The screen assembly must be centralized and a packer must be used. A caliper survey may be needed to aid in estimating the amount of gravel required. If the open hole section "accepts" significantly less than the calculated amount, then gravel bridging in the annulus is probable. A “gravel pack log” is sometimes useful in detecting "open" sections within the pack. Operators gravel packing long, highly deviated holes have reported numerous failures due to inability to fill the annular hole with gravel. The problem becomes severe as the deviation angle approaches 60° from vertical due to bridging problem that prevent downward movement. Possibilities for overcoming this problem may include the using of high viscosity placement fluids to suspend the gravel and, again, to increase the drag forces moving the gravel toward the bottom.

10.15

PUTTING WELL ON PRODUCTION IS A CRITICAL POINT

After gravel packing, the manner in which the well is put on production is quite important from the standpoint of formation damage as well as sand control. The following points should be considered: 1. The formation pores around the well bore are "loaded" with fines carried in by fluids filtering into the formation or by inherent fines made movable by fluid filtrate effects. 2. The fines carried by the produced fluids should be started back toward the well bore as soon as possible, but at a low rate to minimize plugging due to high velocity. 3. To promote bridging of formation sand on the gravel, gradually increasing production rates is also a step in the right direction. So, put the well on production as soon as possible after the gravel is in place. Start with a low rate, gradually increasing to desired rate over a period of several weeks.

10.15.1

LIFE OF THE GRAVEL PACK

A gravel pack should be considered to have a definite life cycle. If the criteria of stopping all formation sand at the outer edge of the pack could be achieved, then the pack should last forever. In practice this is not done, thus sand gradually invades the pack, reducing pack permeability and ncreasing flow velocity in other sections of the pack. Failure is then a progressive plugging situation. 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 migration of fines into a gravel pack can minimized by the use of clay stabilizing organic polimers (Cla-Sta) in the placement fluid. These polymer are strongly adsorbed by clays, and prevent their migration from the formation into the gravel pack. Thus, high production rates can be maintained as well as extending gravel pack life. 10.15.2

USE OF SCREEN OR LINER WITHOUT GRAVEL

For low production rates per foot of section, use of properly sized screens or slotted liner can be a Iow cost means of controlling sand. Selection of a screen or slotted liner, once the slot size has been determined, depends on well conditions. Wire-wrapped screen permits use of harder, more corrosion-resistant metal. Screens set inside casing usually reduce productivity since fine sand moving through the perforations fills the annulus between the screen and casing. Use of largest diameter screen possible is good practice. In open hole, screen should also be sized as large as possible to prevent caving of shale laminations. Underreaming is not desirable. Production should be initiated slowly, particularly with screens set inside casing to reduce erosion until a stable sand bridge is formed.

10.16

RESIN CONSOLIDATION METHODS OF SAND CONTROL.

10.16.1

THEORY OF RESIN CONSOLIDATION.

The basic objective of resin sand consolidation is to increase the strength of the formation sand around the wellbore such that sand grains are not dislodged by the drag forces of the flowing fluids at the desired production rate. Sand consolidation is accomplished by precipitating resin uniformly in the sand near the well-bore. Permeability to oil is reduced because the resin occupies a portion of the original pore space, and also because the resin surface is oil-wet. The formation strength is increased to prevent sand production even though pressure drawdown and drag forces are increased at a given production rate. 10.16.2

RESIN CONSOLIDATION ADVANTAGES.

Properly applied under the right conditions, resin consolidation has inherent advantages: • • • • • •

Suitable for through tubing application. Applicable in small diameter casing. Leaves full open well bore. Suitable for multiple reservoir completions. Can be applied readily in abnormal pressure wells. Works well in fine sands difficult to control with gravel packing.


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Problems Are Multiple: • The basic problem is to increase the strength of the formation uniformly through the completion zone without excessive reduction in permeability. • Many practical problems evolve from the fact that all sand consolidation techniques utilize multistage processes in which several fluids, carefully formulated for the specific well conditions, must be uniformly injected sequentially into a perforated interval. • Fingering of one fluid through another must be controlled by low injection rates and by designing each fluid so that its viscosity is similar or slightly greater than the fluid it displaces.Low fluid viscosities are desirable so that reasonable injection rates can be obtained at low injection pressures. • Time allowed for injection is usually limited. • Most materials used are toxic and highly inflammable. • Resins are very expensive. Where sand production has created a cavity behind the perforations, the cavity must be filled with 40-60 or 20-40 mesh sand before either of the basic resin systems can be used.

10.16.3

RESIN SAND-PACK SYSTEM.

For wells where sand production has occurred (or where a cavity can be created by washing through perforations) Gravel sized to control the formation sand is coated with resin on the surface, then injected into the perforations at below frac pressure until a sand-out is achieved. A screcn or slotted liner is not required, but is sometimes used as a supplemental control device.

10.16.4

RESIN PROCESSES.

Many sand-consolidating resins are commercially available. developped by Shell Exxon, Dowell and Halliburton. Although a number of resin systems are available and many improvements have been made since resin consolidation was first introduced, it should be recognized that well completion and workover methods, placement techniques, and job supervision are usually more important than the specific resin system used. Brine workover fluid (1% KCI) is usually satisfactory. A denser brine (9.5 Ib/gal) placed below the perforations and a lighter brine or diesel placed above the perforations aid in preventing mixing of well fluids with resin materials (density 8.8 Ib/gal) during placement. Fluids containing starch shouid not be used with isopropyl alcohol since an insoluble precipitate is formed. Isopropyl alcohol may also precipitate salt out of highly concentrated brine.


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An injectivity test showing less than 2 gal/min per perforation at below frac pressure indicates that stimulation is needed. In dirty sands, a preflush stimulation treatment (HCI-HF treatment) designed to increase permeability may be required to improve uniformity or resin placement. A preflush could be performed to remove reservoir fluids which might contaminate the resin (water is particularly bad with epoxy resins), and oil wet sand grain surfaces so resin will form continuous coating. The type of preflush used will depend upon the resin system. Resin Mixing and Injeotion—Each resin system has its own peculiarities and requires expert service company supervision. Formation temperature at the time of injection must be known to select the basic resin material in some cases and the amount of accelerator in other cases. Injection of all solutions must be done at low rates (1.0 gal/min per perforation) to promote uniform coverage and at below fracture pressure. The volume of resin varies with the process and, perhaps, the uniformity of the sand. Once performed the treatment, the well must be shut in so that no fluid movement either way occurs through the perforations. A latch-in wiper plug could be beneficial.

10.17

COMPARISON OF SAND CONTROL METHODS SUMMARY.

Gravel pack offers the only practical sand control for long zones. Gravel packing may also be most practical for short zones. Open hole gravel pack must always be used on single completion where water or gas shut off or other change of completion interval is not anticipated. Inside casing gravel pack restricts productivity. But productivity could be maximised by a sufficent number of large clean perforations and effective placement of gravel. Resin Consolidation Is used for short zone where a gravel pack could not be used. Resin sand pack This has most of the same problem and advantages of the inside casing gravel pack.


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TYPE OF ACTIVITY'

ISSUING DEPT.

DOC. TYPE

REF. N.

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P

1

R

1

PAG.

30

8800


Volume 1 CHAPTER 11 - WOROVER -






€

Issued by

REVISIONS

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



PREP'D

CHK'D

APPR'D


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INDEX 11. WORKOVER.................................................................................................................................3 11.1 GENERAL ...............................................................................................................................3 11.2 CONDITIONS REQUIRING A WORKOVER............................................................................3 11.2.1 MECHANICAL PROBLEMS ...........................................................................................3 11.2.2 RESERVOIR PROBLEMS .............................................................................................3 11.2.3 WELL CONVERSION ....................................................................................................3 11.3 WORKOVER PLANNING ........................................................................................................4 11.3.1 TYPES OF POSSIBLE WORKOVERS ..........................................................................4 11.3.2 WELL ANALYSIS.........................................................................................................16 11.3.3 ECONOMICS ...............................................................................................................18 11.4 WELL OPERATIONS ............................................................................................................19 11.4.1 WELL KILLING ............................................................................................................19 11.4.2 FLUID LOSS CONTROL..............................................................................................21 11.4.3 TEMPORARY PLUGGING PILLS ................................................................................21 11.4.4 CHRISTMAS TREE REMOVAL ...................................................................................23 11.4.5 COMPLETION PULL OUT ...........................................................................................24 11.4.6 PARTIALIZATION - LEVEL CHANGE..........................................................................26 11.4.7 FISHING AND MILLING ...............................................................................................29 11.4.8 ENCLOSURE A ...........................................................................................................30


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WORKOVER

11.1

GENERAL

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A workover is defined as Operations to be carried over a well which for a certain amount of time will be shut in to production, causing a production loss to the company. To perform this it is necessary to evaluate a lot of different aspects at the same time selecting the most convenient compromise in term of cost and efficiency.

11.2

CONDITIONS REQUIRING A WORKOVER

Following is a list of motivations which would recommend a workover; natural urgency of restoring maximum achievable production in a well which for some reasones is cutting down, shall meet the overall economic objective of the well itself expecially with regard to its schedule planning and the rest of operating activity. Generally speaking, unless for special reasons, like jeopardized well safety, they are relatively urgent problem to solve and can be scheduled in a convenient and possibly optimized string, expecially with respect to rig availability and their best utilization. On the other hands this last statement shall not cause to perform operations not optimized for the well because of the need of using an available non adequate rig. 11.2.1 • • • • •

tubing collapsed or leaking production casing broken or damaged tubing obstructed (sand, paraffin, asphaltene scales) packer leaking gravel pack damaged

11.2.2 • • • • • •

MECHANICAL PROBLEMS

RESERVOIR PROBLEMS

sand movement (depletion) water coning gas coning perforations plugged emulsion and water blocking clay swelling and silt problems

11.2.3

WELL CONVERSION

Applicable to production wells • • • •

artificial lift installation water injection gas injection storage wells


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11.3

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WORKOVER PLANNING

Following are the minimum steps necessary for a convenient planning: - Evaluation of possible Additional Reserves recovery or of incremental sweep efficiency, - Preparation of Detailed Work Over Program and relevant Budget, - Overall Economics with sensitivity on alternative solutions. To do this all ‘Type of Possible Workovers’ shall be evaluated and best fit to the well under consideration after acomplete and exaustive ‘Well Analysis’.

11.3.1

TYPES OF POSSIBLE WORKOVERS

11.3.1.1

RECOMPLETION

Intervention that is performed when: - well problems heavily reduce the expected production, - to restore the jeopardized minimum safety requirements. It involves the complete pull out of the completion string to eliminate the problem. It is performed always with service rig at high costs

11.3.1.2

HOLE CLEANING

Intervention that is performed when the rising of the rathole sediments obstructs totally or partially the perforations. The intervention can be performed with coiled tubing unit or a service rig. A. Intervention performed with Coiled Tubing Unit: This type of work over is a through tubing activity therefore usually it does not require to remove the completion. The washing string bottom assembly is constituted by a down hole motor and mill (fig 1). The washing is performed circulating a viscosified brine which helps in removing debris while moving down. The production flow is restored lifting through the coiled tubing whit light fluid (diesel, nitrogen). B. Intervention performed with Service Rig: This is a more expensive work over because it is necessary to pull out the completion. It is necessary when either the tubing ID is too small for achieving an efficient cleaning rate or when characteristics of deposits interesting the rathole (scales, asphalthenes) can not be worked out with Coil Tubing carried tools. The activity mainly consists of: - well killing, - puling out of the existing completion,


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- cleaning up and restoring the caracteristics of the fluid in hole, (the used fluid for circulating shall have elevated carryover capacity), -ricomplete the well to restore the production.

HOLE CLEANING

FIG 1

11.3.1.3

PERFORATED INTERVAL PARTIALIZATION

This type of workover is required to eliminate or reduce the production of undesirable fluids (water or gas) from a perforated interval. The intervention could be performed with coiled tubing unity, electric line, service rig. A. Coiled Tubing Unit It can be utilized to spot cement plugs or sand plugs [through tubing], or to set some inflatable bridge plug ( retainers or retrivables); for this last operation there are limitations in the ratio between OD while running and max OD of inflation of inflating tools with respect to the maximum differential 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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pressure they can withstand. Another limitation of this technique is the tendency of these tools to slide inside the not cleaned production casing. B. Electric Line It can be utilized for same A. operations: to set bridge plugs and also to dump cement on top whit a cement bailer (fig 2): it suffers from common limitations of wireline equipments (hole deviation) and allows for the use of tools whose size fit inside the pipe where it is run. C. Service Rig Again this is the most expensive work over because is necessary to remove the completion. The activity mainly is caracterized by: - well killing, - extraction of the existing completion, - setting of cement retainer above the zone that needs to be excluded, squeezing or cement plugging across the perforations, - recompletion. 11.3.1.4

EXCLUSION AND CHANGE OF LEVEL

It is perfomed when the productive level is depleted and or it is not economically exploitable. The intervention could be performed with coiled tubing, electric line, wire line or service rig. 11.3.1.5

FISHING

Intervention that has the purpose to free the well from tools that for various reasons block the well operability; the tools to be fished could have been lost for many reasons: A. wireline tools/wire lost during wireline operations B. section of tubing/downhole equipment lost and/or broken during pulling out C. damaged section of casing weared off by repeated operations done inside or corroded. In case A. the first intervention is always done by wireline itself and in more serious cases with coil tubing. Case B. and C. require always a service rig or a snubbing unit. In (fig 3) there is an overview of tools utilized for these operations.


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DUMP BAILER

FIG 2


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FISHING TOOLS OVERVIEW (fig 3 - a,b,c,d,e,f,g,h,i,l,m,n,o)

a) b) a) bowen surface bumper jar - b) jar decrition - c) packer retriever

c)


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d) e) f) g) d)Internal cutter - e)external cutter - f)junk mill - g) junk mill with circulating system


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h) i) h)junk basket - knukle joint - l) Releasing and circulating overshot

0 1

l)


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m) -n) m) rotary shoe - n) Taper mill - o) drill pipe safety joint

0 1

o)


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11.3.1.6

PAG

0 1

MILLING

This activity has the purposes to eliminate the cement plugs or the tools set in the well which either are not retrievable or which failed to retrieve (i.e. packers, cement retainer) or to prepare the fish head before starting a fishing job. Fig 4-5 show samples of milling tools.

11.3.1.7

PRODUCTION CASING RECONDITIONING

The production casing could be damaged for: • • •

mechanical reasons (excessive pull during the pretensioning, manufacturing defects) flow reasons ( production tbg - annulus, leakage in the production string and presence of corrosive fluids in the annulus) workover reasons (localized wear working on in the same point). Several methods for performing remedial jobs exist:

• •

back-off (unscrew the damaged part and tie back trying to make up new casing joints in the same coupling left); it is usually done with the help of an electrically fired back-off tool run at the desired depth internal casing patch ( utilizzed when there are casing holes or casing breaks.It is made by a rippled metallic jacket dressed externaly by fiberglass and resin that has the function of hydraulic sealing which is run in position and then swaged to the exixting casing. Run in section 40 ft long, it reduces the ID of 0,3”(fig 6)

11.3.1.8

SAND CONTROL

The sand movement is extremely harmful for the well productivity (down hole deposits/plugs) and for the downhole tools (erosion). Principal causes for the sand production are: • • •

loose formation sand reservoirs water production (which reduces intergranular cement) reservoir depletion (which causes formation collapse) Control methods:

• •

flow rate reduction (it causes a reduction of the velocity in perforation tunnels or in the sand face); lately same effect can be obtained with long horizontal drains mechanical methods: - filters - gravel pack - sand consolidation (“resins”)


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11.3.1.9

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ACID TREATMENTS

Principal purpose of acid treatments is to remove the skin damage in the near well bore caused by drilling or workover fluids.

11.3.1.10

FRAC JOBS

Frac jobs are interventions that affect the formation to a notable distance from the well. The aim is to increase the flow area in an homogeneus formation through extended fractures or to connect to main induced fracture a microfractured system in non homogeneus formations.

11.3.1.11

ABANDONING

When a well is not any longer economically exploitable. The abandoning design must prevent the formation fluids migration among different layers behind the casing wall and cement. This operation design shall consider the use of: • • •

cement plugs bridge plugs proper density mud

according to a general scheme approved by Company which follows Local Authorities Regulations. If the production casing is not cemented up to surface, it needs to be cut, the upper part (not cemented ) retrieved and a cement plug in correspondence of the cut installed (fig 7). 11.3.2

WELL ANALYSIS

Before starting any planning or being driven towards inaccurate planning; following problem analysis shall be carried out. 11.3.2.1

ANALYSIS OF WELL PRODUCTIVITY HISTORY

Following data needs to be examined: - historical production data - abnormal pressure/rates trend - presence of unexpected fluids (formation water, gas) - presence of sand

11.3.2.2

ACTUAL WELL STATUS

Following data should be available from the well file:


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- Fluid Composition (last PVT Report): indicators

0 1

to check for paraffin, asphaltines, scales or corrosivity

WELL ABANDONING

Cement retainer

Depth of casing cut

Cement retainer

Depth of casing cut

Cement Drilling Mud Casing cement

Bridge plug

Perforating Interval

FIG 7

- Well Status Report: where to extract informations on: 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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- type of completion - releasing values for packers and anchors - completion scheme (including tubing tally) - production casing (including casing tally) - gravel pack configuration if any - CPI log and production casing CBL, VDL, CET

11.3.2.3

RESERVOIR PROGNOSIS

Following are Reservoir estimations which instead should be discussed and agreed with the Reservoir Department before starting any planning: - water coning (possible effect Water cut abnormal increase) - gas coning (possible effect GOR abnormal increase) - near well bore damage (possible effect PI reduction) - perforations plugging (possible effect PI reduction) - rate decrease (possible effect tubing scaling up) - need for partialization/perforation extension

11.3.2.4

LOGISTIC PROBLEMS EVALUATION

- area preparation - transports - waste treatment and disposal management - environmental safety requirements - equipments storage and handling

11.3.2.5

RIG SELECTION CRITERIA

Depending on the geographic area, on well characteristics and overall workover requirements following considerations should be done: - type, size and availability of rigs (Coil Tubing, Snubbing Unit, Service Rig) - well maximum operative depth - maximum required overpull - rig move constraints 11.3.3

ECONOMICS

Once all above analysis have been done after collecting all necessary informations, following cost indicators should be put together and the whole operation costed to evaluate for its economic impact; sensitivities shall be done with different options if really applicable:


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- rig costs - materials costs - service costs - transports - internal costs

11.4

WELL OPERATIONS

11.4.1

WELL KILLING

- Killing Fluid Selection - Well Killing Procedure and Best Practices for: - killing the well with workover fluid - fluid loss control - temporary formation plugging

11.4.1.1

KILLING FLUID SELECTIN

For its choice there are three important points to consider: • • •

The packer fluid already present in well The workover planned operating sequence The requirement not to damage the formation

A. Fluids characteristics It must be verified the reological stability (vs time and temperature) of the existing packer fluid (expecially in case of heavy fluids) to verify its pumpability and its actual hydrostatic performance in presence of solids settling. It should be verified its compatibility with the formation fluids and rocks. The fluid shall also be solid free or the solids content must be easily removable. B. Fluid Density The actual reservoir gradient not the initial one shall be considered. A heavier fluid is not only more expansive but it would invade the near wellbore (importamt well losses to be considered with the result of possible damage or production decrease. 11.4.1.2

WELL KILLING PROCEDURES

Planning sequence for Well Killing Analyse the completion configuration and mechanical situation.


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Analyse the last P/T survey for calculate the reservoir pressure gradient and determine the killing fluid density. Analyse the last wireline bottom hole survey to verify the rat hole situation (solids settling). Consider the past killing experiences on the same well or on other wells of the same field. Plan to utilize viscous pills and/or removable plugging materials as a contingency. Analyse the formation characteristics and the casing cement bond situation. Choose the killing fluid. Perform all wire line surveys before moving the rig on location. Preliminary operations to Well Killing Calculate killing fluid total needed volume taking into account: - the volume necessary to fill the well - the volume below the pump intake in the mud tank - the volume necessary for circulating and for emergency - the volume foreseen for losses related to formation characteristics Prepare the killing fluid and record the mud pits level. Always start with at least twice the well volume, Inspect the mud circuit, Verify the perfect efficiency of the mud pump, Rig up and test surface lines, Record well head shut in data (tbg, annulus), Plan to circulate for more than one well cycle to homogenize the killing fluid density, Plan to monitor accurately the level in the pits to check for fluid losses to the formation. Single Completion with Packer The procedure to be applied is related to the formation permeability. A.

-The formation takes fluid

The killing operation is performed in bullheading pumping a volume of killing fluid equal to the tubing string plus the volume below packer. An elevated pumping rate is required and pumps do not need to be stopped to avoid the hydrocarbons slipping inside the well whenever the hydrostatic head would decrease. When the killing fluid reaches the perforations an increase of the injection pressure should be noted. A static survey before continuing with the programme needs to be done after a complete well volume has been pumped in. After the static survey, refill the tubing string to evaluate the contingent fluid loss. If fluid loss to formation becomes a problem viscous plugging pills shall be spotted. At the end of puping the well head pressure shall be zero. B.

the formation does not take fluid

The annulus level shall be checked and possibly filled up. The circulation valve ( SSD )in the tubing string above the packer shall be open; if an SSD valve is not present, holes in the tubing string shall be opened (tbg puncher) right above the packer.The illing operation is performed in reverse circulation, pumping from the annulus and having the tubing 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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ide outlet put through the choke manifold to maintain enough tubing head back pressure to controll the well; the circulation shall be continued till the killing fluid shows the same rheological characteristics in and out. Follow performing the rathole killing at hesitation: monitor the tubing well head pressure and bleed off the slipped gas cushions refilling with the killing fluid until the residual tubing head pressure drops to zero. Dual Completion A.

The formation takes fluid

In the job planning the killing fluid volume prepared has to take into account the long and short string volumes. The killing operation shall be done in bullheading for the long and the short string (like in the single completion). Losses shall be monitored accurately because zones could be depleted at different levels. B.

The formation does not take fluid

The SSD in the long string, installed in the lower selection, shall be opened; in case the SSD is missing, holes with tbg puncher need to be done. Circulation shall be estabilished long/short string having the outlet through the choke manifold to maintain enough tubing back pressure to control the well and continued until the killing fluid has the same rheological characteristics in and out. Single Completion with Suspended Tubing String The killing operation is done circulating the killing fluid through the tubing string to the casing. It is important to circulate through the choke manifold to maintain a convenient well head back pressure, on the annulus side, to keep the well under control. The operation shall continue for several cycles (hesitation) until the killing fluid have the same rheological characteristics in and out.

11.4.2

FLUID LOSS CONTROL

It is important to monitor exactly the volume of fluid loss to decide if it can be safely managed. The killing fluid level has to be mantained at well head filling up continuosly to compensate the volume lost for fluid loss. If the fluid loss quantity can not be maintained safely and/or economically it is necessary: • •

to lower the killing fluid density in relation to the actual pore pressure (reservoir depletion). possibly to viscosify the killing fluid

If the well continues to take fluid, then the temporary plugging programme shall be initiated. 11.4.3

TEMPORARY PLUGGING PILLS

The function of a temporary plugging pill is to plug the permeable formation with materials that afterwards can be easily removed leaving the formation undamaged or with minimum damage. 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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A temporary plugging pill shall have the following characteristics: • • • • •

be easily pumpable through the production string, the shape of the solid material shall be sorted to allow to bridge inside the formation, when solid free it shall have cake forming capability on the formation sandface., it should plug only one way, it shall be easily removable either flowing the well back or with a weak acid treatment.

11.4.3.1

CARRIER FLUID

The carrier fluid of the plugging pill shall: • •

allow the pumping of the plugging material through the tubing string, allow for short periods (2-3 min.) the pumping stop without allowing settling of the solid particles.

11.4.3.2

BRIDGING MATERIAL

The choice of the bridging material shall be done on the basis of: • • • •

type of formation, type of permeability (main or secondary permeability), type of formation fluids (water, oil, gas or a combination), completion configuration and down hole parameters (type of completion, temperature, pressure etc.).

On the base of field experience and data available in literature it is recommended to utilize concentrations among 150 - 300 [kg]/ [mc].


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11.4.4

CHRISTMAS TREE REMOVAL

11.4.4.1

TREE AND BOP INSTALLATION/REMOVAL AND TESTING.

These general procedures refer to conventional stacked spool wellhead configuration. - Xmas tree with tubing made up to the bonnet. - Xmas tree whit tubing made up to tubing hanger - Xmas tree for dual completion

11.4.4.2

XMAS TREE WITH TUBING MADE UP TO THE BONNET

This old style Xmas tree (installed in the early Sixties) is rare to be found and it could be met in case of workover in very old wells. Overview of the operating procedure: - Record the well head pressure and fill in tbg-csg at the end of killing, - Open all the xmas tree valves for bleeding possible gas cushions, - Rig down the Xmas tree, - Connect to the bonnet the landing joint with the counterflange, - Remove bolts from the bonnet, - Pull to unset the packer, - Lift the bonnet up to the rotary table, - Take off the hanger “Osmer type”, - Put slips on and unscrew the bonnet, - Make up the tbg hanger H5 with the BPV inserted, - Using a landing joint, land the tbg hanger in the tbg spool, - Install a new ring joint; - Install the BPV plug inside BPV, rig up and test the bop stack against shear rams, - Recover plug and BPV, - Well is ready to pull out the completion.

11.4.4.3

XMAS TREE FOR DUAL COMPLETION

The following general procedure refers to an integral dual hanger: - Insert the BPVs in the tbg hanger - Nipple down the xmas tree recovering the laurent carriers - Run plugs inside Nipple up and test BOP blind rams, - Make up both landing strings, - Perform the test on pipe rams, - Remove plugs and BPVs, - Well is ready to pull out the completion.


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11.4.5

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0 1

COMPLETION PULL OUT

General procedures for the extraction of: - Single completion with retrievable packer, -. Single completion with retainer packer, -. Dual completion.

11.4.5.1

SINGLE COMPLETION WITH RETRIEVABLE PACKER

Calculation for pull to unset the packer: For the calculation following considerations apply: - Calculate string weight with the buoiancy factor, - Add shear value of packer releasing mechanism accounting for shear ring max shear value including span, - Add friction due to the deviation, - Include in calculation a convenient tubing pull reduction to account for wear of tubulars (corrosion) based on field storical data, - If result of calculation exceed the pull capacity of the tubing a contingency procedure to cut the tubing string above the packer should be in place. Packer will then be released using a workstring, Procedure - Wellhead and BOP stack are ready as per previous paragraph, - Loosen the hold down button on the tbg spool, - Unset the packer pulling the string (apply load calculated in previous step), and continue the extraction slowly checking that the weight read on the Martin Decker is close to the theoretical value, - After ten feet stop pulling and perform a static check, - Close BOP (annular) and reverse circulate at least twice the well volume monitoring the possible gas cushions; at the end make a direct circulation for killing fluid homogenization, - Perform static check: if the well still flows, increase the killing fluid density according to residual shut in pressure, if the well takes fluid spot to the bottom a viscosified cushions or a temporary plugging pill, - Pull and bring the Tubing Hanger on the rotary table; break down connection, - Make up additional tubings and run in hole the completion string, adding tubings to circulate the closer possible to the perforations, - Close BOP and reverse circulate thorough choke to control the rathole cushions, - Perform a static check, - Pull out the completion string, monitoring the trip tank level.


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11.4.5.2

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SINGLE COMPLETION WITH RETAINER PACKER

Fixed connection tubing packer A. Snap latch connection - The procedure is the same used to pull the single retrievable packer, with the difference of releasing the Snap Latch which usually require less pull than a shear element. B. Anchor latch connection (left hand connector or solid thread to tubing) - In case of left hand connector, to pull the completion the string shall be tensioned so that its neutral point is at packer depth; then string shall be turned to the right (the objective is to have the correct turn at the packer; to transfer torque to the bottom, the string needs to be reciprocated within its max pull), - in case of solid thread to tubing tubing shall be cut by means of an appropriate tubing cutter. Free moving tubing packer connection A. Standard Locator If the seals are not stuck to retrieve is sufficient to pull the string; a certain overpull can be required for stuck seals.

11.4.5.3

DUAL COMPLETION

- Pull the completion by the dual elevator releasing all the packers if they are retrievable or release the upper packer and pull off the locator from the lower packer, - If all the packers are retrievables they should release together; after the tubing string should be run with the tail as close to the perforations as possible to reverse circulate the bottom cushion, - In case of failure to retrieve, tubings need to be cut. Depending on packer type installed, cut one tubing (the one which possibly does not collaborate to retrieving) as close to packer top as possible; cut the second one at a sufficient lenght above the packer to allow for (playing with the tubing elasticity to move it towards the center of the casing) it being catched with an overshot.


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11.4.6

PARTIALIZATION - LEVEL CHANGE

11.4.6.1

PARTIALIZATION

0 1

It becomes necessary when the formation does produce undesired fluids or start producing sand. The phenomenon is triggered by changes in reservoir conditions, which could be: • • •

reservoir depletion inefficient casing cement bond wrong perforations placement Occurring phenomena could be:

A. Water coning By means of a PLT/TDT log survey, the zone producing water can be identified. B. Gas coning By means of a PLT/TDT-NGS log survey, the zone producing gas can be identified. Possible remedial actions A.Open Hole Possible consequent actions in case of water coning can be: • • •

performing a sand or cement plug with coiled tubing installing a plug (electrically inflatable, damping cement ) with wire line running a liner to cover the zone through a work over with a service rig. Possible consequent actions in case of gas coning can be:

• •

injection of chemical pills (silicates) in bullheading through coiled tubing; silicates should preferentially enter the gas zone (less injection friction loss and block gas production; excess of silicate shall then be cleaned with a coil run motor driven milling tool. running of a liner to cover the zone through a work over with a service rig.

B. Cased Hole - Through Tubing Intervention For same cases mentioned above (gas/water coning) a typical intervention can be done with wire line ( slick or electrical ), coiled tubing or with snubbing unit. Before attempting any operation tubing needs to be cleaned and gaged; tubing scales, deposits can be removed by means of turbine and mill using a viscosified brine as carrying fluid.


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Besides the remedial job illustrated for the cased hole, in this case it is also possible to perform cement squeeze of perforations; the operation has a very high risk of getting stuck with the coil and shall be prepared with great accuracy. - Intervention with Service Work Over Rig This case is classified as heavy workover and requires pulling the completion. The tools utilized are all run on drill pipe; well is cleaned with bit and scraper and workover fluid conditioned. In this case possible alternatives are: - squeeze the producing interval either in bullheadig (low pressure) without cement retainer or with a cement retainer (high pressure) and if possible a reterievable bridge plug to isolate lowermost perforations if the squeeze is done on a top zone, - casing patch the selected interval 11.4.6.2

LEVEL CHANGE

It becomes necessary when the actual producing level is depleted (not any longer economical) or cuts too much water A. Exploitation of an upper zone The methods for the exploitation of the upper level are simple and several times they do not require the well completion pull out. • •

in case of a selective completion, single or dual, the initiation of production of the upper level is done by means of wireline operations (SSD operation) after, if necessary, exclusion of the lower zones closing lowermost SSDs. in case of completions not selective, extension can be done with wireline or coiled tubing setting a trough tubing plug (retainer, retrievable or cement inflated), if necessary, to isolate the lowe zone. Afterwards, perforating the upper zone is done with through tubing guns (wireline or coil tubing conveyed).

B. Exploitation of a lower zone In case a lower zone needs to be open, normaly it is necessary to perform a heavy work over, pulling out the completion: - as a first attempt the upper zone can be squeezed off, - other opportunity is to use a casing patch (which at the end will reduce the casing ID of 1/8” so forcing to use a reduced gage ring OD packer below), - in the event also the casing patch can not be realized a pack off of the level between packer can be realized, - new lower zone can be opened.


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REMEDIAL JOB TOOLS AND TECHNIQUES

Above operations can be accomplished by means of: a) trough tubing bridge plugs b) sand plug c) casing patch d) squeeze techniques A. Trough tubing Bridge Plug. Through tubing Bridge Plugs exist in different shapes available from different manufacturers; they are utilized to exclude the water zones without pulling out the completion. They act as an umbrella to support the cement dumped with a wire line tool (dump bailer); a timer keeps a bypass open for the cement setting.(enclosure A) Also Inflatable Bridge Plugs are available which can be run through tubing without killing the well. They could be run and set by: • wireline and inflated with the work over fluid • coil tubing and inflated pumping through the coil B. Sand Plug. It can be done with C.T. pumping a slurry pill composed by of gel and sands of different size. Sand plugs are usually spotte on top of packer plugs to allow for operations to be done above which could generate settling debris (perforations). They can be easily washed out using viscous fluids. C. Casing Patch The casing patch is a metallic rippled cylinder, dressed externaly with epoxy resins, it is used for size from 2 7/ 8" to 13 3/ 8". The reduction of the casing ID when casing patch is swaged is of 0.3" for standard liner, or 0.48" for a heavy weigth liner. The standard section length of the casing patch is 40 ft, and they can be welded (Tungsten Inert Gas type) to obtain the required length which can also be racked. The heavy weigth version has 3500 psi differential collapse pressure; the casing patch is run and set with the drill pipe D. Cement Squeeze Following reasons can be indicative of squeeze operation needs: • Remedial job to restore casing cement primary bond. • Water shut off of water coming from below the hydrocarbon bearing zone • GOR reduction, isolating the gas cap from the oil • Not or not economically producing zones abandonment • Isolation of zones where fluid loss is important. • D enclosure shows some of the tools utilizzed in squeeze operations


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In general terms, despite being widely used for above operations, squeeze operations are very rarely completely successful even when accurately planned, since they are dependant on a variety of external occurring simultaneous conditions; moreover they are frequently done in formation not well known from petrographic point of view so that volume determination, real cement path during injection and thickening time are frequently guess parameters. For these reasons it is always better when it is required a perfect hydraulic seal to look for alternative pack-off solutions to be istalled as an alternative to squeeze or as a back up. 11.4.7

FISHING AND MILLING

Fishing and milling are two different side of the same coin; both are operations where a great deal of experience is required since they generally do not respond to engineering criteria. Infact even specialized Service Companies rely more on their operators experience than on detailed engineering since it is very difficult to transpond surface machining parameters to downhole conditions which are often affected by load unconformities and tools vibrations. For both activities main parameters to be considered and procedures to put in place are here following listed; some of them need to be stressed more or less, depending on the geographic operative location, since fishing equipment is not always worldwide spread. - Well safety since it is possible to get in situation with the fishing/milling string stuck at the bottom - Type and metallurgy of completion components (Special care with CRA materials), - Type of workover fluid which in these applications act as the milling cooling media besides needing carry over capacity, - Exact well diameters envelope (to select proper shoes, overshots etc.), - Max pull dictated by string age and past operating conditions, - Exact downhole equipment measured reference depths, - Fishing tool availability, - Try to anticipate needs looking ahead and planning for contingencies, - Call for skilled personnel, - Plan any single operation, critically examining the specialist recommended procedure, - Always plan for a correct number of spare jars, accelerators, bumper sub etc., - In case of a heavy fishing job plan for having available a Reversing Tool, - Plan to have wide availability It shall be well considered that fishing services are expensive but nothing is more expensive than paying stand by rates for uncorrect planning. Analysis to be carried over during operations: - Record any parameter, expecially the abnormal ones, - Each time a new fishing battery is run, record and sketch carefully all dimensions (lengths, OD, ID, Irregular shapes, special tools etc.), - Examine carefully tools coming out of the well for wear indication (abnormal, non expected, ruptures, cutting inserts not working etc.), - Examine carefully broken tool edges to plan for next best fishing assembly, - Pay attention to always provide safety joints and fishing capabilities of any new run battery not to worsen the initial scenario, - When milling packers (Expecially CRA ones) pay extreme attention not to insist when no progrees is made to avoid causing a glass type surface which later can be very difficult to attack. 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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ENCLOSURE A

















SPE 22825 Thru-Tubina Inflatable Workover Systems M.P. Coronado,’ R.K. Mody,’ and G.C. Craig, Baker Service Toola ‘SPE Members

rI

This papcr oullincs the dcvclopmcnl of thcsc ThruTublng systcms and application tcchniqucs that have bccn dcvclopcd as a rcsult of thcir ficld use. It d i s c u s s c s case histories of applications using this rcsulting i n c r c a s c i n wcll and the lcchnology This papcr also dcscribes auxiliary pcrformancc. cquipmcnt that has bcon dcvclopcd to allow thcsc 1001 systcms IO bo uscd safcly on coilcd tubing and clcctric wirclinc.

R c c c n t tcchnological advances in inflatablc packing non-convontional ’ design allowcd clomcnt has workovcr tcchniqucs IO be accomplishcd through the The improvod capabilities of thcse production tubing, elements. couplcd with new tool design6 a l l o w i n g w o r k o v e r s IO bc c,omplctcd with coilcd tubing or T h c s e oloctrlc wirclinc, has sccn growing applications. workovcrs include. selcctivc and zona1 chemical lcmporary and pcrmancnl plugback treatments, oporations. intermediato zono blankoff, productlon and injeclion flow profile modifications and formation fracturing. They are complctcd without pulling the An alternato mcthod IO complctc workover opcrations production tubing from the wcll, and thus do not This has bccn dcvclopcd wiihin lhc last fcw years. rcquirc a rig on the wcli. Sincc thcsc tools art snubbcd mcthod involvcs running Thru-Tubing inflatablc 1001s in the wcll with coilcd tubing or clcclric wirclinc, thus through the production tubing and sctting thcm in the clim’naling the nccd to kill the wcll, hcavy wcight kill casina b c l o w t o p c r f o r m zona1 i s o l a t i o n f o r the fluids. which may cause formation damage, art not The production tubing, workovcr proccss (Fig. 1). Thcse tools havc bccn dcsigncd IO operato rcqulrcd. thcrct’orc, stays in placc throughout t h o w o r k o v c r with hydraulic pressure and workstring tcnsion within rccomplclion aftcr the thus making opcration, the coilcd tubing iimitations. The dramatic improvcmcnta in workovcr unnocossary. inflatablc packing clcmcnt design made within the last The advanccmcnt of this tcchnology has Icd to a major fow ycars has now made the expansion and diffcrcntial cast savlng alternative to convontional rig workovcr prcssurc rcquircmcnts for this typc of scrvico possiblo. tcchniqucs. The rcccnt improvcmcnts made in this cquipment has substantially imgrovcd the capabilitics The ability to run tools through the production tubing Major operating and reliability of thcsè mcthods. has obvious advantagcs in the time that is rcquircd I O companics. utilizing thcsc mcthods. have rcalizcd The inflatable 1001s uscd lo complete thesc workovers. substantial COOL savings in thcir workovcr programs. conduct thoso opcrations havc bocn dcsigncd to be run This makcs it porsiblc lo perform on coilcd tubing. This cquipmcnt has bccn dcsigncd IO run through workovcrs without a convcntional rig on site. anothcr major sizcs of production tubing and set in tho largor C o i l o d tubing convcyanco of economie advantage. production casing bciow. The inflatablc clcmcnts have thcsc tools also makcs it possible 10 conduct workovcr t h e c a p a b i l i t y o f b c i n g SCI in casing dismcters over oprations Without killing the wcll, sincc the tools aro lhrce timo6 their run-in diamotct. The 1001s m a y a l s o This climinalcs the possiblc snubbcd in the weil. be utilizcd in wclls with much highcr tcmpcraturcs formation damage that can occur whcn hcavy wcight than prcvious tcchnology allowcd. kill fluid is uscd IO contro1 the w e l i . Rcferenccs and lllustrations at ond of papor

All of the Thru-tubing 1001s that havc b c c n d c s i g n c d a r e centcrcd around the i n f l a t a b l c c l c m c n l .

2

Thtu-Tubing Inflatable Workover Systems

The clcmcnt has bcen designcd in four sizcs to date: 2.13”. 2.50”, 3,OO” and 3.38” O.D. This makcr il possibic to run tools rhrough tubing as smali as 2-7/8”. aiong with che rssociatcd ianding nipplcs in the taiipipc. The ciemcnts sci in casing as largc as 7-5/8” with the 2.13” and 2.50” O.D. ciemenls. 9-518” casing with the 3,W O.D. c l c m e n t a n d IO-3/4” .cssing with the 3-3/8” O . D . Since the toois are 10 bc NII on coiicd tublng ciement. thcrc were design r c q u i r c m c n t s that had lo bc met. The tools havo becn dcsigncd lo operate with oniy hydrauiic prcssurc appiicd to the coiicd tubing and a siight amoual o f t e n s i o n . The amounl of tcnsion rcquind is ~011 within the safc working limils of the coiicd tubing. Auxiliary lools havc bccn dcsigncd to aiiow the tooi string IO bc attachcd IO the coiicd tubing and perform various opcrations safcly. Diffcrcnt 1001 configurations havc bccn dcoigncd around the i n f l a t a b l e elcmcnt lo p c r f o r m various workovcr opcrations. T h c s c opcrations i n c l u d e : pcrmanent and tcmporary water shut offs of iowcr zoncs. zone abandonmcnts, ccmcnt squcezing, gas shut o f f s o f intcrmcditilc eoncs, acid and chcmical trcatmcnts;’ sclcctivc acidixing. downholc flow modificalions, fracturing isolation and production tcsling opcrations. Within the iast two ycars a mcihod IO convcy thcsc tools on ciectric wireiinc has aiso bccn dcvclopcd and bccn uscd cxtcnsivcly in sctiing bridge p l u g s w h c r c accurate dcpth contro1 IS rcquircd. This typc of setting sysiem also has advantagcs in offshorc appllcations w h c r e wirciine services are usuaiiy more raadily avallabic than coilcd tubing.

In 1986 major oii companics opcrating at Prudhoc Bay, Alaska wcre wcli inio the dcvclopmcnt of proccdurcs I O pcrform rcmcdial and stimuiution workovcrs rhrough t h e p r o d u c t i o n t u b i n g utiiizing coilcd lubing. In c o n j u n c t i o n w i t h this cffort, the J’irst fJcld run of a Thru-Tubing packcr, dcscribcd in this papcr. was made in March 1986 al Prudhoc Bay. The firsl Bridge Plug was run in March 1987 at Prudhoc bay. Thcsc rools wcrc m o d i f i c a t l o n s o f cxisting inflalabic ~001s. in 1 9 8 8 , design of a ncw gcncration infialabic packlng elcmcnt was begun lo provide more rcliablc packoff in iargcr size casing at highcr ’ lcmpcraturc and prcssure. in 1989, the first succcssful bridge plug was run and set on elcctric wirciine. Sincc thar lime the typcs and sizes of tools havc bccn cxpandcd IO providc the mcans for performing most rcmcdiai and stimuiation opcrations through tubing as smali as 2-7/8”.

DIFFERENTIAL

PRESSFJRE

TEMPERATURE CAPABILI?iE&

EXPANSJON

AND

Infiatahie improvcd eicment technology was considerably in the early 1980’s with the introduction This clcmcnt is constructcd of the “rib” iype cicment. using thin metri strips which are Iayercd bctwecn the rubbcr seaiing oulcr cover and the rubber innertube. The rib design aiiows much grealer cxpansion and stili maintains the rcinforcement r c q u i r e d f o r the inncrtuk. The rib design riso provides an impmvcd

SPE

22825

cicmcnt to casing anchor which dramatically lncrcascs the diffcrcntiai prcssure rcquired IO make the 1001 slide once it is set. The rib typc cicmcm ailows the elcment I O o x p a n d IO about 1.7 timcs ils origina1 d i a m c t c r . Howcver, pcrforming workovcr opcralions through tubing rcquircs the 1001 bc sizcd IO run through the production tublng and associatcd landing nippics. and havc the cxpansion capabiiity lo set in the casing bclow. i n some appiicalions, thls w o u i d r c q u i r e cxpansinn on the order of 3 timcs its run in diamctcrl. The performance o f t h e r i b t y p c c l c m c n t whcn mcasurcd in rerms of diffcrcntial prcssurc capacity, was furthcr enhanccd using numerica1 tcchniques which wcrc uscd lo dcvclop compulcr modcis lo analyze various dcsigns. New eiastomcr compounds w c r c dcvclopcd Ihat would providc clongation of as much as 400 pcrccnl at 300 dcg F. opcraling tcmpcraturcs, whiic exposod lo wcilborc fluida. The’ combination of ,stluctural slrcngth cnhanccmcnts a n d n c w eiaslomers has cnablcd the dcvclopmcnt of inflatabic clcmcnts ranging in sizcs from 2-i/8” lo 3.3/8” dcsigncd to run t h r o u g h 2-7/8” LO 4-112” produciion tubings. T h c s c clcmcnts aro dcsigncd LO havc a diffcrcntial prcssurc capacity lo nandlc the prcssurcs rcquircd far these workover opcrations. T h c s c Thru-Tubing inflatablc elcmcnts h a v c bucn tcstcd in various casing siacs, wcllborc fiuids and tcmpcraturcs under ficid s i m u l a t c d condiiions as outlincd bclow. Working prcssurc iimlr charts h a v c bccn dcvciopcd from Ihis test dala Tor ficld use (Rcf: Fig. 2 & Table 1). Using compulcr modciing tcchniqucs, some ThruTubing inflatablc clemcnts art now also dcsigncd to SCI i n pcrforatlons, scrccns and siotlcd lincrs. One such unique a p p l i c a t i o n Tor the < 3-3/8” 0-D. i n f l a t a b l e ciemcnt has bccn its use on a rcscttabie scJcctivc lrcatmcnl 1001. Sincc scicctivc scctions of the pcrforalions are isoiatcd, this aicmcnt is dcsigncd IO havc Ihc strcngth rcquircd IO set in 7.0” casing with pcrforations as Irrgc as 1.25” in diamcter. and at ihc samc time withsrand high trcatmcnt prcssurcs. This 33/8” O.D. sclcctivc stimulation clcmcnt has a one time inflation pressare limi1 on the order of 8,000 psi whcn SCI in 7.0” casing and is ablc IO SCI al lcast 20 timcs in Ibis size casing with an inflation prcssum of 4,000 psi. FJELD SIMULATION TESTJNC: All i n f l a t a b i c c l c m c n t tests art conductcd a l tcmpcrature and in various wciibore mcdiumr (cg. to simulate downhole condilions as ciose 8s crude oil), possibie. Horixonlal positioning of the elcment is the 1csts most scvcrc condition during Jnfiation. Hcnce, are conducted in a horizontai poiition IO force the clcment IO centraiize ,itscif i n t h e c a s i n g during . Each si% clemenl IS t c s t e d muiliplc IimGS, i n inflation. various casing sizcs and tcmpcraturcs to oblain data in Long tcrm lcsts of up lo lwo wceks are cach case. c o n d u c l e d IO ensure rubber compound integrity. Elements are tcsted to destruction u p o n c o m p i e t i o n o f t h e tcsting pcriod to obtain u l t i m a t e m e c h a n i c a i slrength information. Once the test is completcd, the faiicd cicments art thcn puiled through various r c s l r i c l i o n s IO simuiatc rctrievin# lhrough i a n d i n g The puii ioad is than nippics in lhc produclion lubing. t a b u i a t c d IO dcterminc the rctricving capabiiitics of these eicments.

’ ,

and G.C. CRAIG CEMENT RETAINER:

L a b teata 10 s i m u l a t e specific field applicrtions ha.ve

al80 been succcssfully c o n d u c t c d i n pcrforttcd crsings, slottcd linerr and scrccns.

The cement retainer has been designcd to be run on either colled or threaded tubing, Thls tool allowr ccment to be placed in the formation below the 1001 through the workstring, a n d a squceze p r e s s u r e O n c e cement is in piace below the reteiner, a applled. flapper valve elosca so squeeze prcssure is mttintrined below the tool. T h e workatring i8 thcn rele88ed f r o m

BRIDGE PLUG:

the retainer with straight puii. Once the workstring is relcascd, a second flappar valve close8 in the retainer, preventing the cemcnt placcd below the 1001 f r o m being contaminatcd by any p r e s s u r c applicd ahove t h e too1. Ccmcnt may then be piaccd above the retainer to aid its long term seallng and anchoring integrity.

The Thru-Tubing bridge plug systems allow isoletion of the wellborc bctween rdjaccnt zones. T h e plugr have b e e n designed in two c a t e g o r i c a : pcrm8nciIt a n d The type of operation required dictatcs rctrieveblc. which plug is applicablc for -the job. The pcrmancnt plug la of 8 simpler design since equalizing a n d retrieving mcchanisms are not required.

A spotting valve has also bcen incorporated above the retaincr lo ai!ow cement lo be spolled to .thc 1001. This

Both plug systems hrvc becn designed to set on either coilcd or thrcadcd tubing, 8s well as o n e i c c t r i c wirelinc wih the U S E of a special setting tool, The bridge piugs hoid differential pressure from ellher dircction. as with ali Thru-Tubing toois. A valving system within *the tool aliows ‘circuiation, or filling of the workstring, when going in the hole, and cioscs off once the piug is set. Inllation pressure is rpplicd to the inflatablc clomant by pressurization of the workslring. or with pressure gencratcd by the wircline setting tool. The bridge plug is releascd from the workaring, or wireline. once 8 prcdctermined amount of”‘inflation pressure is obtained in the clemcnt. - The retrievabie version 8liows equalizatlon acro68 t h e i n f l a t a b l e elcment, before the tool is relcased. to prevent the tool “kicking” whcn bcing rcicascd under differential prcssure.

eiiminates the nccd to pump unwantcd fluids into the formation prior to cemcnling. SELECTIVE STIMULATION TOOL (SST): The SST has bccn deslgncd to allow precise placcmcnt

of treating flulds within a pcrforated interval. The two i n f l a t a b l e cIemettI used on the tooi confine the injection area to 8s liltie as four fccl. The spacing betwcen the eiements is edjustable, prior to running in the holc. The tool is rcscttrblc SO the cntire zone may be treated. Sincc thls tool must set in the pcrforated scction of the wellborc, high ,strcngth clcments wcrc designed for this applicstion.

T h e SST is inflated w i l h p r e s s u r c applicd IO t h e workstrina, which may be eithcr collcd or threadcd T h e rctrievable veraion of the plug is retricved eithcr tubing., _ An inje tion c-ontrol valve ([CV) is run dircctiy Washovcr by workstring o r wireiine means. above rthe SST.- L d -’ 18 uscd to rctain acid or chcmicals r c t r i e v i n g s h o e s have becn dcsigncd to remove fili,._ “‘within’ t h e work~trilig”when t h e t o o l IS deflsted and such 88 sand, from the top of the plug prior to latching bcing moved lo 8 ncw treating position. The SST also onto the plug for rqricval. incorporatcs a spotting valve which la uscd to piace treatment fluids at the tool prior to injection. PACKER:

CHOKE PACKER:

The packer ha8 been dcsigncd to providc isolation for acid or chemical treatments of cithcr iowcr or uppsr zones. The pecker is run in the hole on cithcr coilcd o r threaded tublng and set with hydraulic prcssure applied to the workstring. Once a predetermined amount of inflalion prersure is achicved, a bali seat is blown out the bottom of che tool. Thb providcs a fluid flow path from the workstring to the zone to bc treatcd below the packer sctting dcpth. Uppcr zones may also be treated above the packer by pumping fluidr d o w n t h e backsidc i n t h e p r o d u c t i o n t u b i n g / worksrring annuius. or by means of a bai1 operated circulation valve run above the packcr.

The choke packcr is. a modiflcation of the standard treatiitg packer. The chokc packcr. once set, is reieased from ‘the workstring and ieft in the hoie. The packer is set abovc eithcr a thicf zone in an injcction well. or a h i g h water CUI zone i n a pmduction wcll. With the packer in placc, a chokc asscmbly IS run in and Iatched the packer by means of slickiinc. Once the chokc is in placc, the weil IS cithcr put on injection or production and limiu fluid flow eithcr into or out of the lowcr zone.

IO

The choke asscmbiy may bc retricvcd at 8ny time with slickline lo change orificc size, or rcpiace a w o r n choke. and rerun back in the holc without havlng to

Once treatment operations bave bcen complctcd, the packer is relcased with atraighl puii of the workstring. The pull required for releosc is well withln safe iimits of coiled tubing operalion. If 8t any time the packcr becomes stuck in the hole, a hydr8ulic disconnect may be, activated by circuiatlng -a bali to a seat in the running tool 8bOve the packcr. Once disconnectcd. the workstring may bc pulied from the well and the packer fished with wireline.

pull the packer. PRODUCTION TEST TOOL: The production test tooi has been designcd to isolate certain sections of the pmducing intervais of the well durino nroduction testintt. This tool is a modlfled bridge ‘plug w h i c h all6ws resettability. The tool incoruoratcs an iniection controI- valve (KW which cot&8 t h e inflatiou o f t h e tool by prcssu~ rpplied I o t h e workstting. This tool is 8et in pmgressivcly lower

fr.

. .

Thru-Tubing Inflatable Workover Systems scctions of the wtllbore testing is conducted.

IO

Cm Mdtuy 3:

i s o l a t e diffcrcnt zoncs as

ph@ WIC utlll~d lor # C8n8dlea uperetw b ehut ofl8 loww weter pmducfq teee In # dm well. Pmdectlon lmm Ile nll hed ken stomd by the welu IntrWan. The plup me rrlo11 rlomlt

A 2.73.0. D, pkwnrnrnl lMd28

ELECTRIC WIRELINE SETTING TOOL (E.LINE): The electrlc wirclinc setting tool has bccn dcsigncd lo allow Thru-Tubing bridge plugs, eithcr pcrmancnt or rctrievablc, to be conveycd and inflotcd on eleetrlc T h i s 1s economicrl~y advanlagcous i n wireline*. offshore appli~etiona whcre wire!ine acrvicea are generally more readily availablc than coilcd (ublng. The E-Lino aetdng tool has a collar locator incorpomted in its design for accurate placcmcnr of the plug in t h e well prior lo infiatlon. Once the aelting tool IS activated from the aurfrce, Infladon fluid is drawn out of Ihe wellbon a n d into the p u m p section of the 1001 through The fluid is then pumpcd lnto the inflatable a filter. Once a prcdetermined amount elcment and presaurizcd. o f inllation prcssure ia o b t a i n e d , the E-Linc aeiOng tool and wirclinc are hydraulically relcased from the plug and pullcd from the well (Fig. 3). The actting &ol haa bccn’ dcsigned 10 be compatible wiih all elcctric wirelinc units and wireline sizes.

SPE 22825

wlnulne In Irlr 7’ pmduetlon cestn#. On68 Ih8 plup wee #t. tbla pnme nonmd~l~ well ms broupbt bcX on etmm wtth 8 pmt&@t&r nm 8i t,auo ti,&y*

1

LOWER ZONE ABANDONMENT (Fig. 5): The pcrmanent abandonmcni of a lowcr producing inierval may be achicvcd uaing a permanenl bridge plug as describcd abovc, or by using a ccmcn: retaincr. The ccmcnt rctainer application providca addcd assurance of closing off all zona1 communication by allowing ccmcnt IO bc pumped bclow the io01 and into the abandoncd zone, as wcll as placcd abovc. Ccmcnt may be squcczed into the zone, allowing channeia b e h i n d the casing 10 bc shui o f f . Uaing the cemcnt ,rcrainer is the prcferrcd mcthod for pcrmancnt zona1 abandonmcnt. CEMENT SQUEEZING (Fig. 6):

WATER SHUT OFF

(Fig. 4):

Water shut off opcratlons of lowcr zoncs can be conducted with Thru-Tubing bridge plugs. In order 10 shut off production flow from thcac lowcr’ zoncs. cilher For long a pcrmanent or rctrievablc plug may bc uscd. ttrm pcrmancnt applicationa, a ccmcnt cap may be placcd on top of the plug IO cnsure mainlaincd scal a n d In short tcrm anchoring integrily of the bridge plug. applicalionr whcn a rctricvable plug is uaed, calclum c a r b o n a r e articulatc (CaCO3) is placed above the plog. T h i s malerial. b c i n g a c l d aolublc. facilltatcs casy rcmoval prlor IO retricving the bridge plug. Sand may alao bc used aa P bridging agent abovc the plug. When the plug needa lo be SCI in short target inrcrvals bclwccn perforatcd scctions of the lincr. it may be set by mcans of clcclric wircline wilh the use of Ihc E-Linc aetting tool. The aclting taoI has a built in collar locator which pruvides grcatcr accuracy in dcpth control.

cere Rlrkvy 1: A Norlh Se8 pps?etor, rllltzle# e 3.W 0.0. permenenl btiddn plup succeeelully lenl8led 8 lower weh pnduch# zoa# In Illr P cesln# end ImeeH oll ptWrcn#r whih dcln~ mhr wi etpellkenuy. Iamet wall

pmtncilan ~8s 3,600 BOPU wlfh 8 wel#r cvt al 24%. Af&r Inslelletlon al tbe plng, pmductlon wee Incmee8d to 6,400 BOPO mifb 8 water cui ol only 1%.

..

Ccmcnt squcezc jobs conduclcd to shut off certain watered or gasscd out zonca may be accomplishcd with a squecze packcr. The packcr ia set above the zone to be squcezcd, and cement spolted Lo the top of rhe tool. This eliminatcs unwantcd fluida from bcing placcd in the formation prior IO placemcnt of the ccment. Once the ccmcnl ia in placc, and a aquecze prcaaurc oblaincd, the packcr is relcaacd with atraighl pull of. the workstring. The casing is then cleancd ouL of unwantcd ccmcnt b y revcrsc circula~lon of the workalring, o r b y u s i n g an undcrrcamcr in conjunclion with a slimlinc mud motor run on coilcd tubing. lf an inlcrmcdiatc zane ia IO bc squcczed 10 shut off a gas producing interval, a bridge plug’ is act below the target interval for isolation purposea prior Lo ronning Iht squceze packer. Calcium Carbonate articulatc ia spoucd on top of the bridge plug prior IO cementing IO p r c v c n t .ccmcnt reaching the plug.’ Once the rqucczo ia completcd and the wcllborc clcancd oul, the plug is relcascd and rctrieved.

NON-CEMENTED GAS ZONE SHUT OFFS (Fig. 7 and

8): Intcrmcdiate gas zoncs may bc shut off by isolating Ihe interval with two inflatable p a c k c r a Ihat art connecrcd This straddlc packer arrangement providea togclhcr. allows production shut off of the dcsired gas zone. yct from the lower zoncs through the tool’s mandrcl. If the z o n e to b c iaalatcd ia the uppermor.. i n the wcll, P A packcr slightly differcnt configuration may bc uacd. IS hung off in the cnd of the production Iubing tail by m e a n a o f a l o c k i n g mandre1 in a wirellnc Ianding nipple. und blank tubing IS un bc~wccn the locking The packer is positioned mandre1 a n d Ihe packcr. bclow the g a s z o n e . T h e p a c k e r ia then inflaled by Whcn the applying prcaaurc to the productlon tubing. deaircd pressure is obtaincd, a plug blowr out the cnd of Ihe packer providing unrcslriclcd flow up through the packcr aaaembly. .I

9

e .

l

,.-.I

SPE., 228251; _<_. ._..-_--._

_

M.P. CORONADO, R.K. MODY and G.C. CRAIG

5

T h i s mwhod IS aiso uscd In injection weils w i l h i o w c r zone thicf intcrvals. The choke packer is set abovc lhc lhicf zone, lhus iimiling injcction flow into thal z o n e . As a rcsuil, the uppcr zones musi now takc a grcalcr The rcslriction of flow amounl of the injcclion fluid. imo thcsc t h i c f z o n e s r c s u i l s i n a m o r e uniform swccping pallern of the reacrvoir.

ACIDIZINC AND CHEMICAL TREATMENTS (Fig. 9): Isolation of zones lo bc lrcated with ncid or oihcr typcs of chcmicais are accompiished by using a combination The bridge of a retricvabie bridge piug and a packer. p i u g is sci b e i o w the trcalmcnt i n l c r v a l p r i c r l o running the packer. The packer is lhen run in on a coiicd tubing workslring and set abovc the inlcrvai. Once the packer is set, treatment fluids are pumped inlo Once the the trealmcnl intcrvai through the packcr. treatment fluids art in piace, lhc packcr I S rcicascd and puiied from the wcii. Tlrc wcii can now be put back on any unwanlcd acid or produclion to fiow bi\ck The bridge piug may latcr chtmicais in the formation. be relricvcd from the wciiborc. c8S8 h/S!OQ’.’ AMO 0.0. p8&&8r ~8s ollllrel br 8 m.Ur 011 COmp8nYln Ptudhon B8Y l0 p8tiOmV ZM81 hl8fiOn Of Upp8f Wf7M ih’ fh# ?” h81 durln# 8 mUd 8tld 8tlrnarllan. pIplrrcllan 8llar 1118 tn?8mM ~88 Incmnsed lo 2. MO UOPO imm 818l8ot¶H #OPDbefm~h8/ab.

SELECTIVE ACIDIZINC (Fig. 10): Acid stimulalions o f oniy a porlion o f a zone i s accompiished wilh a sciccdvc slimulalion lo01 (SST). This looi uscs two inllr~lablc clcmcms which seal off a scclion of t h e pcrforalions. as s h o r t a s Tour fect. f o r The scicclivc stimuiation tooi is scicclivc lrealmenls. .rcscllabie, a i i o w i n g the cntirc z o n e I O b c stimuiated. This providcs a mcans of knowing lhe cxacl piaccmcnl A spotling v a l v e incorporatcd i n o f lreatmcnt lluids. the. tooi design. abovc lhc iop cicmcm. aiiows lrealmcnt fluids to bc spolled IO the 1001 prior IO injccling .inlo the This prcvents unwantcd fluids from bcing formalion. pumpcd into lhc inlcrvai ahcad of the lrcalmcnl fluids.

FLOW PROFILE MODIFICATIONS (Fig. Il and 12): Fiuid flow profiies across the pcrforalcd s&tion in the wciiborc may bc altcred with lhc use of a downhoic chokc packcr. In a produclion wcii, with a iower zone pfoducing a high ratio, of walcr, fiow from this zone can be rcstricfed by scliing a chokc packer abovc the zone. Once the packcr IS SCI, a choke receplacie is run in and latchcd lo lhc packer by means of winiinc. This reccplacie houscs a chokc bean which is sizcd far the specific appiicalion. The wcii is lhen put back on production and fiaw fmm the iowcr zone is rutriclcd. This resuils. in a Iowcr water CUI in the productlon fluid. If the desircd resuils art not obtaincd. the rectplacic may be rctricvcd from the wcii on wirciinc a n d t h e chokc bcan rcslzed and run back in the wcii. withoul rcicasing the packcr.

FRACTURING (Fig. 13): Rclricvabic bridge plugs nrc uscd for zone isolation in fracluring opcrntions of uppcr intcrvals. The piug is set bclow lhc zone IO bc fraclurcd lo isolate the from lowcrmost zoncs the fraclurc lrcalmcnt. Fracluring is lhcn conduclcd lhrough lhc production F.did tubing ond a sand out prcssurc oblaincd. c x p c r i e n c c u s i n g this mclhod has sccn a dramalic incrcasc in the bridge piug’s diffcrcntiai p r c s s u r c capscity with lhc fraclure sand on IOP of the piug. Fracturc sand out prcssurcs as high as 4,000 psi ,havc bcen oblained abovc a 2.13” 0-D. bridge piug whcn set in 7” casing. Whcn comparcd IO the prcssure raling shown in Fig. 2, lhis prcssurc significantiy cxcccds the rallng of lhc lo01 whcn SCI in lhis slzc casing. Once the fracturing opcralion is compielcd, the bridge piug is rcmovcd from the wcii by washing down over the plug with coiicd lubing. PRODUCTION TESTING (Fig. 14): Thru-Tubing production lcsling may bc accomplishcd by cithcr of two methods. The firsl mclhod invoivcs using a rclricvablc bridge piug which is SCI bciow the uppcrmosl produclion inlcrvai. Once the piug is set, the wcii is pul on produclion and Mow data oblalncd. Aftcr lhc initiai productiou test, the piug is removcd from lhc wcii and rcrun. IO a position bciow lhc nexl i o w c r p r o d u c t i o n Tho wcil is again put back on production and imcrvai. T h i s proccdurc is rcpcatcd unti1 l h c d c s i r c d tcstcd. z o n c s art tcncd. The s c c o n d m c l h o d u l i i i z c s a modificd pcrmancnt bridge plug which har bccn dcsigncd to bc rcscttabic. This design utiiizcs an injcclion controi valve which IS opcralcd wilh coiled tubing prcssurc. Appiicd prcssure IO the coiicd tubing opcns the valve and. infialcs the piug. Once the piug is set, the weii is put on production and lcsted through the produclion tubing / coilcd Whcn the test has bccn compiclcd, tubing annulus. appiicd coiicd lubing pressurc is rcieascd aliowing the injcction. contro1 valve lo ciosc and the eicment lo defiale. The 1001 IS lhen posilioncd bciow the neyt iowcr produclion inlcrval, whcrc it io rcsC[ and the ncxt produclion ICSI conducted. This mcthod provider a more efficicnt opcralion when comparcd IO using a bridge plug. whcn multiple sclting of lhc lcsling tool is requircd. -

__--.

_

.

r

Thru-Tubing Inflatable Workover Systems

6

T h o t w o maln moans of running a Thru-Tublng tool in the hole is on coilcd tubing and elcctric wirollne. Small rizc Ihrcadcd tubing can òe used, but coilod rubin5 and Flgurcs 15 and 16 w i r o i i n o havo many advantages. show cxamples of typical tool strings run whcn sctting a bridgo plug on coiled tubing and clcctric wirclinc. COILED TUBING CONVEYANCE: Coiled tubing has gaincd in popularity in the last fivc years. The advanlago of collcd tubing over thrcadcd tubing is the spccd that il can be run in and out of the holc, and the ability IO s n u b the tubing in the hole, e l i m i n a t i n g the necd IO kill the wcll prior IO workovcr Coilcd 1ubing is availablc in sizes from operations. 0.75” IO 2.00” O,D., with 2.38” O.D. and larger dlametcr . 1ubing IO bc dcvelopcd in 1ho ncar future.

Collcd

Tublng

Operation:

The Thru-Tubing inflatable tools are run in the wcll with acccssory 1001s spccifically designcd IO porform v a r i o u s csscntial opcrations. Sctting of 1he inflatable 1001 is accomplishcd by pumping fluid down Ihe tubing Il is good coiled tubing proclice a n d in10 the element. to have the ability to circuiate fluid through the tubing while going In the hole. T h c r c f o r e a ball IS usually pumpcd down the lubing af1ct reaching’ setting dcpth I O ac1ivate the 1001 a n d initiatc 1hc setting opcralion. Othcr 1001 string funclion s u c h as cqualizing, o p c n i n g circulating valves and cmergency disconntcting aro a l s o ini1ia1ed by pumping halls through the coiled tubing. WIRELINE

CONVEYANCE:

Electric wirclinc providcs a quick and Fccuratc mcans of deploying and sctling Thru-Tubing bridge plugs in tho wcll. With the use of a collar locaror. propor sclting Wircline also dcpth can bc achicvcd quitc accurarcly. providcs a quick mcans of rclricving plugs. With the srrcngth of brnidcd wirelinc, along with jars. a Iatge amounl of force is a v a i l a b l c f o r the rctricving operarion.

WireLinc

Operation:

T h r u - T u b i n g bridge plugs can bc sc1 on clcctric wireline by mcans of an E-Linc sctling 1001. The b r i d g e plug. cither pcrmancnt or rctricvable, is run to seiting dcpth and .SCI by applying voltage to the wirelinc. Whcn the, dlcmenl is inflaled, the incrcase in prcssurc actuatcs a hydraulic disconncct and the set1ing 1001 IS The setting procedure i s freed from the plug. monilored al lhc surface by obscrving .the currcnl transmittcd through 1hc w i r c l i n e . T h e rctrievable b r i d g e p l u g i s o f t c n rclricvcd o n A modificd wircline rc1rieving 1ool is braidcd wirclinc. l a t c h e d onlo a fishieg neck on top of the plug. An upward jarring force rclcases. the 1001 SO thrt it can be relricved from rhe well.

SPE 22825 ’

.

A completo complemoni of accossory tools havc bcen dcvelopod 10 insurc sale opration in both coilcd tubing and elcctric wircline appllcations (Fig. 17). COILED TUBING CONNECTOR: T h e c o i l c d l u b i n g connccior providcs a means of connecting d o w n h o l e lo01 strings lo 1hc c n d o f t h e coilcd tubing. The coilcd tubing wall thickncss is ioo thin 10 thread cffcclivcly, S O the auachmcnt musi b e made in othcr ways. Wclding of the 1001 string onta the coiled 1ubing is also impractical since this rcsults In a w c a k c n i n g of 1hc tubing in the hcat cffeclcd zone S o m e o f the attoching mcans atc slips, ICI creatcd. scrcws and the flaring of the cnd of the tubing. Once the conneclor IS attachcd IO the coilcd lubing, a Joint is formcd which is strongcr than the coilcd iubing itsclf. A pressure 1ighc scal i s p r o v i d c d i n the conneciion, sincc 1hc opcration of the Thru-Tubing tools rely o n hydraulic pressurc applicd to the workstring. .. BACK PRESSURE VALVE: Onc of the advanlages of Thru-Tubing 1001s is that the wcll docs noi havc 10 be killcd to pctform the rcmcdial or slimulation workovcrs. S O during m o s t opcrationa the wcll is live. The coiled lubing unit has a full set of BOP rams lo prcvcni 1hc wcll f r o m b l o w i n g o u t . bui Ihore is slill tho possibilily of a lcak i n t h e t u b i n g ai a u r f a c e ’ above the lubricator. Such a Icak poscs a safeiy, as wcll as cnvironmcnlal h o r a t d . The back prcssurc valve is run in 1hc tool string bclow the c o n n c c t o r lo prcvcni flow up through the t u b i n g in the cvcnt of coilcd tubing failurc a1 the suriace. This is a flappcr valve design that allows flow down, but no1 up the 1ubing. Sincc mosr of the Thru-Tubing 1001s are controllcd by pumping a ball from the surface, the flappcr valve is dcsigncd to allow a ball to pass thtough with minimum fluid flow. LOCATING TOOL: II is normally noi a good practicc lo locare sctting deprh by mcans of the dcp1h ‘indicator on the coilcd tubing u n i i . A sciling dcpth l o c a t c d b y this mcihod will probably noi bc on target, unlcss the allowablc setling interval is largc. Sciting dcpth can bc locatcd from the boltom of the hole, bui this Icads IO crror b e c a u s o o f unknown amounis of fill in the hole. A mcchanical locator. run in the rool string, p r o v i d o s an indicalion o f the tubing iail dcpth SO 1hc coiicd tubing dcplh counter can bc adjustcd. The locator givcs an indicarion on the wcight indicatot when il IS pulled upwards inlo the The locatoy a l s o g i v c s indications o f tubing tnil. landing nipple dcpths in Lhc tailpipe. Once 1ho cnd of tho mblng IS locatcd. the d e p t h i s corrclaled wi1h a w i r e l i n c l o g o f the wellborc IO p o s i t i o n the ThruT u b i n g 1001 in the corrcci localion w i i h i n t h e production casing. EMERGENCY DISC~NNECT: All coilcd tubing jobs requirc a mesns 10 disconncct the lool sIring from the coiled tubing if the tools b c c o m c stuck in the holc. Wlrclinc tools also rcquire a backup _ _ _. _P

L

_ __ _.. _~__

_. -_. .-._- _ --._ _... .___

l

22825

SPE

Prarrurc

dirconncctitig merhod. Coiltd tubing is rclatively w c a k compared IO thrcadcd tubing, and practically no lubing manipulation is availablc IO the 1001 opcrator. For these reasons a means of dlsconnectlng that docs noi r e q u i r c a g r e a t a m o u n t o f pull o r t u b i n g manipulrtion is reauircd. Whcn Ihe disconnect ir activatcd. and the tu6ing r e m o v a d f r o m t h e well, P,sre io a profile lookinn UD f r o m Ihe fish t h a t c a n b e latched o n t o easily.-This allows going back in the holc with braidcd wireline and latching onto the flsh. The braided line, with retrieving tools. providcs a means of pulling the fish out of the hole. Pr11

Ditconncct:

ING BBU)GE PLUW

The Hydraulic Disconncct is acIivetcd by pumping a bnll Io a scat within the tool and applying workslring pressure. The 1001 is pressure balanced prior IO Ianding the ball on seat, SO premature releasing is avoided. This tool can be used in more 1001 strings than the pull dirconncct bccause il is not activatcd by tubing tension. The hydraulic disconncct is splined IO p r c v e n l spinning. SO it can be uscd wlth tools’ thot create torqui. such as slimline mud motors.

Retrieval of Thru-Tubing bridge plugs utilizing coiled tubing has becn dcvolopcd within the lasi few ycars. Most of this dcvclopmcnt has bccn in the Prudhoe Bay tield of northem Alaska3. The advantages discusscd carlier in runnlng Thru-Tubing tools on éoiled tubing ia also applicablt lo f i s h i n g . strinns. The flshina m e t h o d s devtloped LO rctrie& bridje plugs. 0ncC workover opcrations are completed, can bc groupcd main in10 thrcc categorics: washovcr retrieval utilizing coilcd tubing. rotary fishing also using coilcd tubing and wircline. retrieval. One o f thcse threc methods art incorporatcd dcpcnding on whcthcr thcre is Il on .top of the plug, and the type of fili prescnt.

two imoty: b tbo Ydb 60#, M opommr CI1 a wii wim wvon Dotlum wibm sbiisu In lim uppof pmducill# intetwk Ol ut0 wn. Tb8 wmp /illw6pm#wfi0R wm Mese w(MI, cvtib the w!l pmdacirg 8r a mm d 1,34I 6#6 rnd 8n

WASHOVER RETRIEVAL:

80% wlor cut, A coilod ‘lrbinp convoyod mn?orrermor / mud n#?lor rss8mbty l ioitfl wifh 8 bydmuik dkconnod rnd MC& ptuuum v8in ~88 urad Io cit?811 ruf fbir seui~~n ol ihc wiik~m lo msfon pndmdimt /mm fM#e zu~~s. Alier ih8 ci#rroui, /br w#il dmduced 4JdU IOPO wiib 8 42% wfor cut.

This retricval tcchniquc is uscd whcn a fill is on top of the plug that may be placcd in suspcnsion by slow thruugh the coiled tublng. This method is commonly k n o w n as w a s h o v c r rctrieving. This is aoulicablc if eithcr sand or cnlcium carbonaie is above the plug. A typical washovcr recricving tool string is illustratcd in Fig. 18.

VALVE!%

The circulating valve IS a means of cstablishing communication betwcen the tubing and annulus. This communication path can bc uscd to spot fluids. to cqualize pressurc from tubing IO annulus, or providc a c i r c u l a t i o n port directly from the tubing IO t h e annulus.

Oprratrd

Circulatintf

Valva:

The Fluid Loading Valve allows placing cnough fluid in the end of the coilcd iubing al the surfacc, prior I O running the (001s in the holc. to inllafe a bridge plug. This is requircd whcn sctting a pluy in a gas well with no fluid in the wcllborc ai sctting depih. The bridge plug must bc set with a fluid to achicvc Ihc desircd and scallng abllity anchorlng o f the inffatable elcment. Al sening dcpth this Iluid can bc pushcd imo the inflatable elemcnt with nitrogcfi prcssurc applicd IO the coilcd iubing at the surfacc IO set the plug.

manncr that allows it to bc shcarcd apart with a prcdctermincd load. This cool has limitcd use since it is noi usually run wi\h o t h c r t o o l s lhat r e q u i r e pull lo A special pull disconncct has becn designcd lo operale. be used with the E-Line scaing tool to act as a back up releasing devicc in the event the primary hydraulic relcrse fails 10 operate.

BaII

Clrcul~ting

FLUID LOADING VALVE:

The pull disconncct is dcsigncd 10 be held togcther in a

CIRCULATING

Opcratcd

The pressure operatcd valve has an unbalanced slecvc that can be pumped open by applicaUon of workstring pressure. As with the ball operatcd valve. the tool muat allow circulation through the workstring going in Be holc. With .this design, the valve operating prcssurc is adjuslablc and must be lompatible hydraulically w i t h the other cquipment In the toor sIring.

Dirconncct:

Hydraulìc

7

M.P. CORONADO, R.K. MODY and G.C. CRAIG

Once the bouom of the washover shoe reacher the top of the sand fili. flow through Lhe coilcd tubing placcs the sand in suspenslon in the coiled tublng / casing annulus. The tool string may Ihcn be lowered unti1 the washover shoe Iatches onto the bridge plug’s fishingncck. Latching of the washover shoe opcns equallzing porls within the plug allowing prcssure above and below the plug LO cqualizc prior to releasing of the Once cqualizing IS completed, the bridge plug IS plug. relcascd with straight pull of the coiled tubing string. The bridge plug, once nleased and deflatcd. will retum lo its prc-inflated O.D. allowing retrieval back thrbugh the production tubing.

valve:

The ball operated c i r c u l a t i n g v a l v e contains a slecve on the jnside of the tool which is shifted open once a ball is circulated I O rhe tool a n d pressure applicd Io Ihe The valve may be adjusted before running workstrlng. in the hole for different opening pressurcs. The ball valve is p r e s s u r e balanccd d u r i n g t h e operated inflation and treatment operationr untii the ball 1s The tool must allow circulation of Iaaded on its seat. fluid through che workstring going in the bolc, for inflatlon and subsequcnt treal.ment operations, prior 10 opening the valve.

Hydraulic actuatcd cenlral,izers. coiled tubing knuckle joinls, hydraulic actuated disconnects and hydraulic jars havc aiso been developcd to aid in these fishing operadons. These dcvices. whlch are p1so sised IO pass through the production tubing, provide the means lo ntrieve the bridge plugs lypical wellbon in any .

.

Thru-Tubing Inflatable Workovet Systems deviation. The increased usagc of the Irrger sixcs of coilcd tubing workstrings (l-l/2 - 2”) has made coilcd t u b i n g f i s h i n g o p c r a t i o n s practical. T h e l a r g e r diamctcr tubing has Incrcased strcngth compared to the smallcr sizcs. and also highcr pump rates may be obtaincd to clcar sand off of the plug prior to latching onto the fishlng ncck. ROTARY RETRIEVAL: Tbis mcthod is similar to the washover retricval systcm describcd abovc with the addcd fcaturc of rotary movcmcnt of the lowcr fishing asscmbly. Various skirts are uscd wlth the rotary mcthod including: hookwall, toothcd and burning skirts. Thcse types of ;:.lrts a r e r e q u i r c d w h e n materia1 above t h e p l u g cannot bc rcmovcd wlth circulation through the coilcd tubtng. This is oftcn cncountcrcd when ccmcnt clcanout of the wcllbore is rcquircd abovc the plug, prior to rctricval, and largcr picccs of ccmcnt fafl on top of the plug. A typical rotary rctricving tool string is illustratcd in Fig. 1 9 . The rotary mcthod utili& a slimline mud motor, eized to run through the production tubing, to providc the rotary action of the lowcr assembly. Once clcanout of the fili above the plug I S obtaincd, the fishing string latchcs to the bridge plug as in the washover mcthod. The plug is thcn rclcased with the aid of hydraulic jars.

SPE

22825

casing bclow. Futthcr clastomcr devalopment will allow thesc tools to pcrform in lncrcaslngly hostilc cnvironmcnts with rcliability. With the lncrcascd UIC of coiled tubfng as production strings, thia typc of infletablc tcchnology will bs cxtrcmely useful. The Thru-Tubing tools havc becn dcsigncd prlmarily for coilcd tubiug use. SO thcir application to production strings scems Iogicrf. Only a fraction .of the possible applications for thcsc Thru-Tubing inflatable systems havc bcen realizcd and applicd to Ecld operations. The ability to pcrform nonrig workovcrs using coiled tubing or electric wirclinc convcyancc has dramatically reduced the cast of the& workovcrs. The application of Thru-Tubing inflatablc systcms will undoubtcdly bc uscd lo grcat advantagc in the ycan to come.

The authors would likc to thank Baker Scrvice Tools for the opportunity to publish this paper and also Frank Richardson, John Sprott. Joe Thomton and Lisa Bunch for their valuable contributions in prcparing this papcr. The autbon’ also greatly apprecirte the cfforts o f t h e A l a s k a . N o r t h Sea a n d Canada regions i n supplying case history information.

WJRELINE RETRIEVAL: Mody, R. K.. and Coronado, M. P.: “New Gcncmtion Inflatable Packing clcments”, OTC papcr 6755 presented at the 23rd Annual OTC Technical Confercncc, Houston, Tx., May 6-9, 1991.

Wircline retricval of Thru-Tubing bridge plugs is applicablc when thcrc is no flll on top of the plug and wcllborc deviation does no1 prohibit wirelinc use. The wirelinc tool string is much the samc as that uscd in any fishing operations with the exception of a special h o u s c d pulling t o o l w h i c h allows cqurlizrtion o f prcsaures across the plug prior to releasing. The cquslization of the bridge plug hns increascd importencc in wirclinc fishing due to the largo unbalanced arca working on the plug whcn set in Iarge casing, and the wirclinc’s inability to s u p p o n any load- in compression and rclatlvcly little in tcnsion. The mcchanical mcthod for equalixing thesc plugs will n o t rllow the wirelioe pulling 1001 to latch up 10 the bridge plug without the cqualizing valve bcing opencd first. This provides a fail safc mcthod to ensurc equalization prior to rclcasc of the plug and prcvcntion of wirclinc failurc. Braidcd wirclinc is also rccommcndcd for bridge plug fishing opcrations due to its increascd strcngth and better compatibility with hydraulic jarring. A typical wircllne rctricving tool string is illustrated in Fig. 20.

Mcndcx, L. E.. Coronado, M. P., and Holdcr, D. J.: “Field Use of Thru-Tubing Blcctrlc Wireline Set Bridge Plug Systcm”. OTC papcr 6459 prcsented at the 22nd Annua1 OTC Technical Conferencc, Houston, Tx.. May 7-10, 1999. Mullin, M. A., McCarty. S. H.. and Plantc, M. E.: “Fishing With 1.5 and 1.7S-in. Coilcd Tubing at Western Ptudhoc Bay. Alaska”, SPE papcr 20679 prcscntcd at the 65th Annua1 SPE Technical Confcrence, New Crlcans. La., Scptcmbcr 23-26, 1990.

T h e substsntial increase in performance of ThruTubing inflatable tools realizcd within the last fcw years has vastly incrcascd the potential of inffatablc workover production operationr. and The c n h a n c c m c n t s i n b o t h mechanical s t r t n g t h a n d elastomcr propcrtics (in both clongation and ttmpcraturc compatibility) will bc furthcr advrnccd in the near future. Both the structural s t r e n g t h a n d elastomcr performance cnhancements will enable the dcvelopment of smaller diamcter systcms thrt could be run through Z-3/8” production tubing and set in larger

_

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.

SPE 22825

a

P F

%

c

l

: i

l.

Fig. 9: I9omion of tm8tmml u8ing 9pciur9ndMd!UPkJg

Fig. lo: 9ebcliw ackJizing using rn 9ST

Fig. 11: Dawnhok flo~ COIWOI Using Production Choka Packor

Fig. 12: Downhoi flow control uring an injection chob packor

i

i Fig. 14: ptudllctlon

t88tlng ImIng

Pmductlonm8ttool

wE 2282 .

’

BAU OPERATEO CIRCUUTING VALVE

PRESSURE OPERATI 0 CIRCUWT1NC VALVI

COILED TUBING CONNECTOR

.

HYDRAULIC DWONNSCT

TUBINC E N D LOCATOR

PULL DISCONNECT

FIG. 17: ACCESSORY TOOLS

87

BACK PRESSURE VALVE

--.~.- -

- - - ____~

WRELMR ROPL SOCRRT

COILED TURINC CONNBCTOR

IEIOHT

BAR9

HYDRAlJuC CENTRALIZER HYDRAULR! DISCONNBCT

HYDRAULIC DISCONNECT HYDRAULIC JAR

OIL JAR

HYDRAULK JAR

YUD YOTDR HYDRAULIC CENTRAUZER

VIREUNE JAR HYDRAUWC DISCONNECT OVBRSNM

W

OVSRSHOT

FIG. 18: TYPICAL COILED TUBINC UASHOVER RETRIEVING TOOL STRINC

HOOMALL SKIRY

FIG. 19: TYPICAL COILED TUBING ROTARY RETRIEVING TOOL STRING

RETRIRVMC TODL

FIG. 20: TYPICAL WIRELINE RETRIEVINC TOOL STRiNG

I

P1R8789A Well Completion & Workover Manual Volume1

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