The liquification is a common problem produced mainly in natural gas wells specially in reservoirs of retrograde condensate gas like Camisea in Peru for example.

Liquid loading can lead to erratic, slugging flow and decreased production. The well may eventually die if the liquids are not continuously removed. Often, as liquids accumulate in a well, the well simply produces at a lower rate than expected.

1.2 Multiphase Flow in a Gas Well
1.3 What is Liquid Loading?
1.4 Problems Caused by Liquid Loading
1.5 Deliquefying Techniques Presented
1.6 Source of Liquids in a Producing Gas Well
1.6.1 Water Coning
1.6.2 Aquifer Water
1.6.3 Water Produced from Another Zone
1.6.4 Free Formation Water
1.6.5 Water of Condensation
1.6.6 Hydrocarbon Condensates

2 Recognizing Symptoms of Liquid Loading in Gas Wells
2.1 Introduction
2.2 Presence of Orifi ce Pressure Spikes
2.3 Decline Curve Analysis
2.4 Drop in Tubing Pressure with Rise in Casing Pressure
2.5 Pressure Survey Showing Liquid Level
2.6 Well Performance Monitoring
2.7 Annulus Heading
2.7.1 Heading Cycle without Packer
2.7.2 Heading Cycle with Controller
2.8 Liquid Production Ceases
2.9 Shooting Fluid Levels on Flowing Gas Wells
2.9.1 Fluid Level—Gas Flow above Critical Rate
2.9.2 Fluid Level—Gas Well Shut-in
2.9.3 Fluid Level—Gas Flow below Critical Rate
2.9.4 Estimation of BHP from Fluid level Measurement
2.9.5 Acoustic Determination of Liquid Loading in a Gas Well

3 Critical Velocity
3.1 Introduction
3.2 Critical Flow Concepts
3.2.1 Turner Droplet Model
3.2.2 Critical Rate
3.2.3 Critical Tubing Diameter
3.2.4 Critical Rate for Low Pressure Wells—Coleman Model
3.2.5 Critical Flow Nomographs
3.3 Critical Velocity at Depth
3.4 Critical Velocity in Horizontal Well Flow

4 Systems Nodal Analysis
4.1 Introduction
4.2 Tubing Performance Curve
4.3 Reservoir Infl ow Performance Relationship (IPR)
4.3.1 Gas Well Backpressure Equation
4.3.2 Future IPR curve with Backpressure Equation
4.4 Intersections of the Tubing Curve and the Deliverability Curve
4.5 Tubing Stability and Flowpoint
4.6 Tight Gas Reservoirs
4.7 Nodal Example—Tubing Size
4.8 Nodal Example—Surface Pressure Effects: Use Compression to Lower Surface Pressure
4.9 Summary Nodal Example of Developing IPR from Test Data with Tubing Performance
4.10 Chokes
4.11 Multiphase Flow Fundamentals
4.11.1 Fundamentals of Multiphase Flow in Wells
4.11.2 Application of Multiphase Flow Correlations for a Well Producing Gas and Free Water 68

5 Sizing Tubing
5.1 Introduction
5.2 Advantages/Disadvantages of Smaller Tubing
5.3 Concepts Required to Size Smaller Tubing
5.3.1 Critical Rate at Surface Conditions
5.3.2 Critical Rate at Bottomhole Conditions
5.3.3 Summary of Tubing Design Concepts
5.4 Sizing Tubing without IPR Information
5.5 Field Examples #1—Results of Tubing Change-Out
5.6 Field Examples #2—Results of Tubing Change-Out
5.7 Pre/Post Evaluation
5.8 Where to Set the Tubing
5.9 Hanging Off Smaller Tubing from the Current Tubing

6 Compression
6.1 Introduction
6.2 Compression Horsepower and Critical Velocity
6.3 Systems Nodal Analysis and Compression
6.4 The Effect of Permeability on Compression
6.5 Pressure Drop in Compression Suction
6.6 Wellhead versus Centralized Compression
6.7 Downstream Gathering and Compression’s Effect on Uplift from
Deliquifying Individual Gas Wells
6.8 Compression Alone as a Form of Artifi cial Lift
6.9 Compression with Foamers
6.10 Compression and Gas Lift
6.11 Compression with Plunger Lift Systems
6.12 Compression with Beam Pumping Systems
6.13 Compression with ESP Systems
6.14 Types of Compressors
6.14.1 Rotary Lobe Compressor
6.14.2 Liquid Injected Rotary Screw Compressor
6.14.3 Liquid Ring Compressor
6.14.4 Reciprocating Compressor
6.14.5 Reinjected Rotary Lobe Compressor
6.14.6 Sliding Vane Compressor
6.15 Gas Jet Compressors or Ejectors
6.16 Other Compressors

7 Plunger Lift
7.1 Introduction
7.2 Plungers
7.3 Plunger Cycle
7.4 Plunger Lift Feasibility
7.4.1 GLR Rule of Thumb
7.4.2 Feasibility Charts
7.4.3 Maximum Liquid Production with Plunger Lift
7.4.4 Plunger Lift with Packer Installed
7.4.5 Plunger Lift Nodal Analysis
7.5 Plunger System Line-Out Procedure
7.5.1 Considerations before kickoff
7.5.2 Kickoff
7.5.3 Cycle adjustment
7.5.4 Stabilization period
7.5.5 Optimization
7.5.6 Monitoring
7.5.7 Modern Controller Algorithms
7.6 Problem Analysis
7.6.1 Motor Valve
7.6.2 Controller
7.6.3 Arrival Transducer
7.6.4 Wellhead Leaks
7.6.5 Catcher Not Functioning
7.6.6 Pressure Sensor Not Functioning
7.6.7 Control Gas to Stay on Measurement Char
7.6.8 Plunger Operations
7.6.9 Head Gas Bleeding Off Too Slowly
7.6.10 Head Gas Creating Surface Equipment Problems
7.6.11 Low Production
7.6.12 Well Loads up Frequently
7.7 Two Piece Plunger: Type of Continuous Flow Plunger
7.8 Selection of Plunger
7.8.1 Continuous Flow Plunger Lift
7.8.2 Types of Continuous Flow Plungers
7.8.3 Conventional Plunger Lift
7.8.4 Evaluation Process
7.8.5 Deciding Which Type of Plunger to Use
7.8.6 Progressive/Staged Plunger Systems
7.9 Casing Plunger for Weak Wells
7.10 Plunger with Side String: Low Pressure Well Production
7.11 Plunger Summary

8 Use of Foam to Deliquify Gas Wells
8.1 Introduction
8.2 Foam Assisted Lift (FAL)
8.2.1 Introduction
8.2.2 Well Diagnostics
8.2.3 Foaming Agent Selection
8.2.4 Application and Assessment
8.2.5 Conclusions
8.3 Methods of Application of Surfactants
8.4 Capillary Lift Technology
8.4.1 Conventional Capillary System Installations
8.4.2 “Foot” Valves
8.4.3 Controlled Siphoning Applications
8.4.4 Controlled Positive Injection Applications
8.4.5 Capillary Tubing Strings
8.4.6 Capillary Hanger Systems
8.4.7 Basic Operating Procedures for Installing and Removing
Conventional Capillary Systems
8.4.8 Hooke’s Law—Basic Capillary String Stretch Calculations
8.4.9 Non-Conventional (Externally Banded) Capillary System

9 Hydraulic Pumping
9.1 Introduction
9.1.1 Applications to Dewatering Wells—Gas and Coal Bed Methane
9.1.2 Limitations of Other Forms of Lift
9.1.3 Advantages of Hydraulic Pumping
9.1.4 Disadvantages of Hydraulic Pumping
9.1.5 Types of Operating Systems
9.1.6 Types of Subsurface Pump Installations
9.1.7 Parallel-Free Installations
9.1.8 Fixed-Type (Or Tubing Conveyed) Installations
9.1.9 Fixed-Insert Installations
9.1.10 Fixed-Casing Installations
9.1.11 Wireline-Type Systems
9.1.12 Ancillary Equipment
9.1.13 Power Fluid Choices
9.2 Jet Pumps
9.2.1 Theory
9.2.2 Cavitation
9.2.3 Emulsions
9.2.4 Sizing Considerations
9.3 Piston Pumps
9.3.1 Operation
9.3.2 Single Displacement Pump
9.3.3 Double Displacement Pump
9.3.4 Piston Velocity
9.3.5 Fluid Separation
9.3.6 Piston Size
9.3.7 Selecting a Pump
9.3.8 Surface Power Fluid Conditioning Systems
9.3.9 Central Power Fluid Conditioning System
9.3.10 Trouble Shooting

10 Use of Beam Pumps to Deliquify Gas Wells
10.1 Introduction
10.2 Basics of Beam Pump Operation
10.3 Pump-Off Control
10.3.1 Design rate with pump-off control
10.3.2 Use of surface indications for pump-off control
10.4 Gas Separation to Keep Gas Out Of the Pump
10.4.1 Set pump below perforations
10.4.2 “Poor-boy” or limited-entry gas separator
10.4.3 Collar sized separator
10.4.4 Benefi ts of Downhole Gas Separation in Dewatering Gas Wells and in Low Pressure Oil and Gas Reservoirs 297
10.5 Handling Gas through the Pump
10.5.1 Gas Locking
10.5.2 Compression ratio
10.5.3 Variable slippage pump to prevent gas lock
10.5.4 Pump compression with dual chambers
10.5.5 Pumps that open the traveling valve mechanically
10.5.6 Pumps to take the fl uid load off the traveling valve 321
10.5.7 Gas Vent Pump® to Separate Gas and Prevent Gas Lock (Source: B. Williams, HF Pumps)
10.6 Inject Liquids below a Packer
10.7 Other Problems Indicated By the Shape of the Pump Card

11 Gas Lift
11.1 Introduction
11.2 Continuous Gas Lift
11.3 Intermittent Gas Lift
11.4 Gas Lift System Components
11.5 Continuous Gas Lift Design Objectives
11.6 Gas Lift Valves
11.6.1 Orifi ce valves
11.6.2 Injection pressure operated (IPO) valves
11.6.3 Production pressure operated (PPO) valves
11.7 Gas Lift Completions
11.7.1 Conventional gas lift design
11.7.2 Chamber lift installations
11.7.3 Horizontal well Installations
11.7.4 Coiled tubing gas lift completions
11.7.5 A gas pump concept
11.7.6 Gas circulation
11.8 Lift without Gas Lift Valves
11.9 Specifi cs of Gaslifting Gas Wells

12 Electric Submersible Pumps
12.1 Introduction
12.2 The ESP System
12.3 What is a “Gassy” Well?
12.4 Completions and Separators
12.5 Special Pump (Stages)
12.6 Injection of Produced Water
12.7 ESP hybrid systems and low liquid volume ESP
12.7.1 Special Adaptation to Conventional Centrifugal ESP
12.7.2 Electric Submersible Progressing Cavity Pump (ESPCP) and Electric Submersible Progressing Cavity Pump through Tubing Conveyed (ESPCP TTC)
12.7.3 Hydraulic Diaphram Electric Submersible Pump (HDESP)

13 Progressing Cavity Pumps
13.1 Introduction
13.2 Progressing Cavity Pumping System
13.3 Water Production Handling
13.4 Gas Production Handling
13.5 Sand/Coal Fines Production Handling
13.6 Critical Tubing Flow Velocity
13.7 Design and Operational Considerations
13.8 Pump Landing Depth
13.9 Restricted on No-Flow Scenarios
13.10 Presence of CO2
13.11 Corrosion Inhibitors
13.12 Cyclic Harmonics
13.13 PC Pump Selection
13.14 Elastomer Selection

14 Coal Bed Methane
14.1 Introduction
14.2 CBM Economic Impact
14.3 CBM Reservoirs
14.3.1 Reservoir characteristics
14.3.2 Flow within a CBM Reservoir
14.3.3 CBM Contamination
14.3.4 Coal Mechanical Strength
14.4 CBM Production
14.4.1 Deliquifi cation Plan
14.4.2 Gathering Plan
14.4.3 Wellbore
14.4.4 Flow lines
14.4.5 Separation
14.4.6 Compression
14.4.7 Deliquification

15 Production Automation
15.1 Introduction
15.1.1 Gas Well Deliquifi cation
15.1.2 Gas Well Dewafering
15.2 Brief History
15.2.1 Well-Site Intelligence
15.2.2 Communications
15.2.3 System Architecture
15.3 Automation Equipment
15.3.1 Instrumentation
15.3.2 Electronic Flow Measurement
15.3.3 Controls
15.3.4 RTUs and PLCs
15.3.5 Host Systems
15.3.6 Communications
15.3.7 Database
15.3.8 Other
15.4 General Applications
15.4.1 User Interface
15.4.2 Scanning
15.4.3 Alarming
15.4.4 Reporting
15.4.5 Trending and Plotting
15.4.6 Displays
15.4.7 Data Historians
15.5 Unique Applications for Gas Well Deliquifi cation
15.5.1 Plunger Lift
15.5.2 Sucker Rod Pumping
15.5.3 PCP Pumping
15.5.4 ESP Pumping
15.5.5 Hydraulic Pumping
15.5.6 Chemical Injection
15.5.7 Gas-Lift
15.5.8 Wellhead Compression
15.5.9 Heaters
15.5.10 Cycling
15.5.11 Production Allocation
15.5.12 Other Unique Applications
15.6 Automation Issues
15.6.1 Typical Benefi ts
15.6.2 Potential Problem Areas
15.6.3 Justifi cation
15.6.4 CAPEX
15.6.5 OPEX
15.6.6 Design
15.6.7 Installation
15.6.8 Security
15.6.9 Staffi ng
15.6.10 Training
15.6.11 Commercial vs. “In House”
15.7 Case Histories
15.7.1 Success Stories
15.7.2 Failures
15.7.3 Systems That Haven’t Reached Their Potential
Appendix A: Development of Critical Velocity Equations

A.1.1 Physical Model
A.2 Equation Simplifi cation
A.3 Turner Equations
A.4 Coleman et al. Equations

Appendix B: Development of Plunger Lift Equations
B.1 Introduction
B.2 Minimum Casing Pressure
B.3 Maximum Casing Pressure
B.4 Summary
B.5 Reference
Appendix C: Gas Fundamentals
C.1 Introduction
C.2 Phase Diagram
C.3 Gas Apparent Molecular Weight and Specifi c Gravity
C.4 Gas Law
C.5 Z factor
C.6 Gas Formation Volume Factor
C.7 Pressure Increase in Static Column of Gas
C.8 Calculate the Pressure Drop in Flowing Dry Gas Well: Cullender and Smith Method
C.9 Pressure Drop in a Gas Well Producing Liquids
C.10 Gas Well Deliverability Expressions
C.10.1 Backpressure equation
C.10.2 Darcy equation


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