Dynamic Simulation of Gas-lift Wells and Systems

API RECOMMENDED PRACTICE 19G11 FIRST EDITION, OCTOBER 2018

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Copyright © 2018 American Petroleum Institute

Foreword

This recommended practice is under the jurisdiction of the API Committee on Standardization of Production Equipment (Committee 19).

This document presents recommended practices for dynamic simulation of gas-lift wells and systems. Included are steady state models, pseudo steady state models, and dynamic numerical models. Other API specifications, API recommended practices, and Gas Processors Suppliers Association (GPSA) documents may be referenced in system design and operation.

The verbal forms used to express the provisions in this document are as follows.

Shall: As used in a standard, “shall” denotes a minimum requirement in order to conform to the standard.

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May: As used in a standard, “may” denotes a course of action permissible within the limits of a standard. Can: As used in a standard, “can” denotes a statement of possibility or capability.

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Contents

Page

1. Scope 1

2. Normative References 1

3. Terms, Definitions, Abbreviations, and Symbols 1

   1. Terms and Definitions 1

   2. Abbreviations 6

   3. Symbols 7

4. Introduction to Dynamic Simulation of Gas-lift Wells and Systems 7

   1. General 7

   2. Definition of Steady-state Models 8

   3. Definition of Pseudo-steady-state Models 8

   4. Definition of Multiphase Flow Transient Numerical Simulation Models 9

   5. Dynamic Simulation Basic Concepts 9

   6. Two-phase, Three-phase, and Drift-flux Models 10

   7. Comparison of Steady-state and Dynamic Simulation Techniques 16

   8. Limitations of Steady-state Flow Evaluations 16

   9. History of Multiphase Flow Modeling 19

5. Recommendations for Implementing Dynamic Simulation of Gas-lift Wells and Systems 21

   1. General 21

   2. Choose Type of Model to Use 21

   3. Applications, Benefits, and Methods of Implementation of Dynamic Models 22

   4. Information Required for Dynamic Simulation 26

   5. Information Provided by Dynamic Simulation 29

   6. Dynamic Behavior of Gas-lift Wells and Systems 33

Annex A (informative) Case Histories 38

Annex B (informative) Applications, Benefits, and Implementation 58

Annex C (informative) Information Required for Dynamic Simulation Processes 77

Annex D (informative) Information Provided by Dynamic Simulation 81

Annex E (informative) Overview of Gas-lift Systems and Applications 104

Bibliography 118

Figures

1. Dynamic Simulation Continuity Illustration 12

2. Section Volume and Section Boundaries 13

3. Section Volume and Section Boundaries 13

4. Example Simplified Well Completion Schematic 14

5. Dynamic Simulator Flow Regime Groups 14

6. Well Cleanup with Lost Circulation Material (LCM) Viewer Snapshots Sequence 17

7. Slugging Flow, Front and Tail of the Gas Bubble 18

1. Penguins Field Schematic Layout in Relation to the Brent Charlie Platform 39

2. Dynamic Model of Well Including Annulus 42

3. Profile of Each Well 42

4. Comparison of Dynamic Simulator X and Steady-state Simulators Y and Z 43

5. Simulation Results for Case 1 44

6. Simulation Results for Case 2 45

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   Contents

   Page

7. Simulation Results for Case 3 45

8. Simulation Results for Case 4 46

9. Simulation Results for Case 5 46

10. Simulation Results for Case 6 47

11. Simulation Results for Case 7 47

12. Simulation Results for Case 8 48

13. Comparison of Simulator X and Y at 2 MMscf/d Gas Rate 49

14. Comparison of Simulator X and Y at 4 MMscf/d Gas Rate 50

15. Comparison of Simulator X and Y at 8 MMscf/d Gas Rate 50

16. Overview of Slug Frequency and Size vs THP 51

17. Rate vs Time for THP of 1 bar and 5.2 bar 51

18. Rate vs Time for THP of 13.8 bar and 18.6 bar 52

19. Rate vs Time for THP of 20.7 bar and 25.5 bar 52

20. Average Daily Liquid Rate vs THP 53

21. Effect of Orifice Port Size on Flow Stability 53

22. Initial Design Evaluation 54

23. Design Evaluation After Redesign 55

24. Gas-lift Design 55

25. First Unloading Simulation 56

26. Unloading Simulation with Revised Design 57

1. Example Well Production Trend 59

2. Well Loading-up—Dynamic Simulation (Gas in Grey; Liquid in Blue) 60

3. Well Dynamic Simulation Output Comparison (Gas in Grey; Liquid in Blue) 61

4. Typical Flow History of a Gas Well 62

5. Liquid Transport in Vertical Gas Wells 63

6. Minimum Gas Rate for Unloading a Well 63

7. Liquid Transport in a Vertical Gas Well 64

8. Tubing Performance Curve in Relation to Well Deliverability Curve 64

9. Illustration of an ICD 66

10. Possible Cross-flow Situations During Well Flowing 67

11. Possible Cross-flow Situations During Well Shut-in 67

12. Effect of Tubing Performance Curve on Liquid Production Rate 68

13. Effect of Gas-lift Rate on Liquid Production Rate 68

14. Integrated Technical Operating Information Management System 75

15. Integrated Simulators Under a Unified Software Environment 76

1. Vertical Well Profile 83

2. Horizontal Well Profile 83

3. Multilateral Well Completions 84

4. Vertical Well Profile (Y = Depth; X = Deviation from Vertical) 85

5. Illustration of Common Vertical and Horizontal Multiphase Flow Patterns 86

6. Schematic of Well/Flowline Common Geometries 86

7. Effect of Critical Velocity in Horizontal/Inclined Flow 87

8. Inside Diameter Scale Deposits 87

9. Dual-pocket GLM Cutaway with Scale 87

10. Changes in Flow Patterns in a Vertical Well with Pressures and Temperatures 89

11. Flow Pattern Map for Vertical Upward Flow 89

12. Well Production Rate (Black Dots) is in the Gravity-dominated Area,

    Left of the Minimum of the Intake Pressure Curve (IPC) 90

13. Well Trajectory Can Trigger Terrain Slugs 91

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    Contents

    Page

14. Illustrations of Riser-induced Slugging 91

15. Example P, T, and Water Condensation Rate Values Along the Flowline Profile 92

16. Hydrates P-T Curve—EOS: PR78 Peneloux 94

17. Hydrate Margin in Riser vs Time During Well Kickoff—

    60 MMscfd, 15 Water-Gas Ratio, Profile Data (°C)—Riser Length (m) Time (min)9 94

18. Hydrate Dissociation Curves with MeOH Inhibition (0 % to 60 %) 95

19. Hydrate Inhibition Curves with the Overlaps of the

    Worst-case P-T Trends from Riser Profile Plots 95

20. Tracking MeOH Injection and Hydrates Potential 96

21. Thornhill-Craver Equation and VPC Model Valve Performance Comparison 99

22. Thornhill-Craver Equation and VPC Model Orifice Performance Comparison 100

23. VPC Model Performance Comparison with Different Load Rates 100

24. Stem Travel Valve Performance Comparison 101

25. Valve Size Performance Comparison 101

26. Comparison of Valve Performance with and Without a Choke 103

1. Continuous Gas-lift Production Processes 104

2. Schematic of Dual Gas-lift Installation 106

3. Intermittent Lift Cycle 109

4. Plunger Lift with Gas-lift System 111

5. Schematic of an Auto Gas-lift Well 113

Tables

1. Applications of Dynamic Simulation 11

2. Most Popular Empirical and Mechanistic Multiphase Flow Correlations 20

1. Details of Each Case 43

2. Comparison of Simulators X and Y for Cases 1, 3, 5, and 7 at 0 % Water Cut 44

3. Comparison of Simulator X and Y for Case 5 at 95 % Water Cut 48

Dynamic Simulation of Gas-lift Wells and Systems

1. Scope

   
   

   This recommended practice (RP) provides guidance and background for the application and use of dynamic simulation of gas-lift wells and their related systems. Discussion is included for use of steady-state, “pseudo” steady-state, and dynamic numerical models. Also presented are guidelines to facilitate the application of these techniques to optimize well/system integrity, operations, life cycle design, and production. Additionally, a range of artificial lift and natural flowing systems and topics (e.g. gas well liquid loading) are addressed. The dynamic simulation recommendations (e.g. stable flow, hydrates, waxes, corrosion, liquid loading, and complex wells) can be implemented in other production systems (e.g. natural flowing wells).

   
   

   This RP is also designated for managers, production technologists, reservoir engineers, facilities engineers, production engineers, well testing engineers, well analysts, operators, and researchers who want to gain a general understanding of dynamic simulation, areas of application, added values, and benefits. The contents compare transient vs steady-state techniques and provide readers with when and how each technique may be effectively applied.

   
   

   Not included are technical requirements for the hardware of the dynamic simulation system, the specifics of the system calculations, the responses to the output of the dynamic simulation data output, and specifics of what actions are required after the provided data is considered.

   
   

   An extensive bibliography is provided of documents for additional information on the topics included.

   
   

2. Normative References

   
   

   There are no normative references in this document.

   
   

3. Terms, Definitions, Abbreviations, and Symbols

3.1 Terms and Definitions

For the purposes of this document, the following terms and definitions apply.

beaning-up

The process of increasing the wellhead choke size to adjust the flow rate for adjustable choke.

NOTE For fixed chokes, it is the same process, excluding shutdown periods.

black oil correlations

Assumes that the reservoir fluids consist of three phases: oil, water, and gas.

NOTE These are defined with a minimum of information [specific gravity, gas-oil ratio (GOR), and water cut], with gas dissolving in oil and oil vaporizing in gas. Water is assumed to be inert. Use correlations to determine the fluid properties at different pressures and temperatures (P-T).

boundary conditions

Fluid type, flow rate, pressure, and temperature values assigned to the selected model boundaries (inputs, outputs, and surrounding environment of the model) used in solving the differential equations that apply to dynamic simulation.

1