DEVELOPING RATIONAL CRITERIA FOR GAS/OIL/WATER/SAND …ewemen.com/wp-content/uploads/2016/03/Mamudu-A.O._M.Sc... · 2016. 3. 31. · MAMUDU ANGELA, B. Eng. Chemical Engineering. A

© 2016 Ewemen Resources Limited. All rights reserved. www.ewemen.com

DEVELOPING RATIONAL CRITERIA FOR GAS/OIL/WATER/SAND

SEPARATION METHODS

By

MAMUDU ANGELA, B. Eng. Chemical Engineering.

A dissertation submitted in partial fulfilment of the requirements of the award of

Master of Science in Oil and Gas Engineering at the University of Aberdeen

(September, 2012)


Mamudu Angela Onose Page ii

PLAGIARISM AWARENESS DECLARATION FORM.

SCHOOL OF ENGINEERING

COVER SHEET FOR MSc DISSERTATION

COURSE CODE: EG5908

SECTION 1: TO BE COMPLETED BY STUDENT

SURNAME/FAMILY NAME: MAMUDU

FIRST NAME: ANGELA

ID Number: 51123956

Date submitted: 13TH SEPTEMBER 2012

Please:

Read the statement on “Cheating” and definition of “Plagiarism” contained over the page. The full Code of Practice on Student Discipline, Appendix 5.15 of the Academic Quality Handbook is at: www.abdn.ac.uk/registry/quality/appendices.shtml#section5

Attach this Cover Sheet, completed and signed to the work being submitted

SECTION 2: Confirmation of Authorship

The acceptance of your work is subject to your signature on the following declaration:

I confirm that I have read, understood and will abide by the University statement on cheating and

plagiarism defined over the page and that this submitted work is my own and where the work of

others is used it is clearly identified and referenced. I understand that the School of Engineering

reserves the right to use this submitted work in the detection of plagiarism.

Signed:

Date: 13TH SEPTEMBER 2012

DATE RECEIVED: 13TH SEPTEMBER 2012

SUPERVISOR: PROFESSOR HOWARD CHANDLER

http://www.abdn.ac.uk/registry/quality/appendices.shtml#section5


Mamudu Angela Onose Page iii

ABSTRACT

The process of separating reservoir fluids into their distinctive phases is termed indispensable as

all other processing stages depend on the quantity and quality of its product. Although at the early

days of oil production, the well stream separation process was carried out based on the physical

differences observed within its components; a lot of modifications and developments has since

then be recorded.

This research aims to investigate and analyse the different separation technologies currently

being used in the oil and gas industry, particularly outlining the factors that need to be considered

for the suitability of each technology at different operating condition.

This was achieved by carrying out a detailed review on the: fundamentals of oil and gas

separation process, mechanism or principles that govern each process, parameters that

determine its efficiency, effects of the produced solids on the equipment, formation and the

environment as a whole, various separation technology used to separate the liquid phase from the

gas phase and also the separation of solids and other extraneous materials from the reservoir

fluids, citing case studies were necessary.

This review conducted shows that although the different technologies used for the separation of oil

from gas have their unique pros and cons as discussed in the main body; they include the use of a

vertical, horizontal and spherical separator, a gas-liquid centrifugal cyclone, gas scrubber with the

recent ones being the use of subsea water separation plant, inline separation and the pipe

separation technology. The production limit, convectional exclusion and the inclusion technology

were recognized as the means of separating produced solids from the well fluid.

Overall seven rational criteria were being identified to be the factors behind the selectivity of each

technology. They include the relative amount of gas and oil in the well stream, the variation in

densities between the liquid and the gas phase, the variation in viscosities between the liquid and

the gas phase, the operating parameters at which the separation process is to be carried out and

the level of re- entrainment observed.


Mamudu Angela Onose Page iv

DEDICATION

This work is dedicated to the blessed memories of:

Mrs Anne Ayedun, you will forever be remembered.

Mr Lucky Igoki, I miss you so much.


Mamudu Angela Onose Page v

ACKNOWLEDGEMENTS

My profound and sincere gratitude goes to:

God Almighty for giving me the gift of life, strength, wisdom and understanding to

complete this thesis.

My parents, Sir Adams Mamudu and Lady Tina Mamudu for their words of

encouragements, love and support.

My supervisor, Professor Howard Chandler, for his invaluable contribution to the

success of this work.

To my siblings, Mr Mamudu Anthony and Dr. Miss Mamudu Anthonia for their

continuous faith in me.

All my friends, home and abroad for all your support, prayer and advice.


Mamudu Angela Onose Page vi

TABLE OF CONTENTS

COVER PAGE…….…………………………………………………………………..i

PLAGIARISM AWARENESS DECLARATION FORM……………………………ii

ABSTRACT…………………………………………………………………………...iii

DEDICATION…………………………………………………………………………iv

ACKNOWLEDGEMENT……………………………………………………………..v

TABLE OF CONTENT…………………………………………………………….vi-x

LIST OF FIGURES………………………………………………………………..x-xii

LIST OF TABLES……………………………………………………………………xii

NOMENCLATURE………………………………………………………………xiii-xv

CHAPTER ONE: INTRODUCTION

1.1. Background Study and Problem Statement………....................................1

1.2. Well Fluid Separators………………………………………………………......2

1.3. Modifications………………………………………………………………….....2

1.4. Research Intent………………………………………………………………....3

1.5. Scope of Work………………………………………………………………......3

1.6. Research Justification

1.6.1. Educational Sector……………………………………………………………..4

1.6.2. Industrial Sector………………………………………………………………..4

1.7. Thesis Structure………………………………………………………………..4

CHAPTER TWO: FUNDAMENTALS ON OIL AND GAS SEPARATOR

2.1. The Importance of a Separating Process…………………………………...6

2.2. Definition of Oil and Gas Separator……………………………………….....6

2.3. Classification of Separators

2.3.1. Classification by Operating Pressure………………………………………...7

2.3.2. Classification Based on Configuration……………………………….7

2.3.3. Classification by Application………………………………………….11

2.3.4. Classification Based on their Function……………………………...13

2.3.5. Classification Based on the Number of Phases……………………14

2.3.6. Classification by Principle…………………………………………….15

2.4. Common Component of Oil and Gas Separator

2.4.1. Primary phase separation section…………………………………….15

2.4.2. Secondary/ Gravity Settling Section………………………………….15


Mamudu Angela Onose Page vii

2.4.3. Mist Extraction or Coalescing Section………………………………..16

2.4.4. Liquid Accumulation Section…………………………………………..16

2.4.5. Process Controls………………………………………………………..16

2.4.6. Safety Devices……. …………………………………………………….17

2.5. Comparison of the Pros and Cons of Oil and Gas Separators ……….........17

2.6. Internal Components of Gas-Oil Separators

2.6.1. Mist Extractors……………………………………………………….….18

2.6.2. Vortex Breaker……………………………………………………….….21

2.6.3. Wave Breakers………………………………………………………..…22

2.6.4. Inlet Diverters…………………………………………………………....22

2.6.5. Sand Jets and Drains…………………………………………………...22

2.6.7. De-foaming Plates……………………………………………………….23

2.7. The Operational Procedure of Oil and Gas Separators

2.7.1. Primary Stage…………………………………………………………….23

2.7.2. Secondary Stage…………………………………………………………..........24

2.7.3. Final Segregation………………………………………………………….........24

2.8. Maintenance Procedures for Oil - Gas separators

2.8.1. Periodic Inspection…………………………………………………………......25

2.9. Operational Problems in Separator

2.9.1. Foamy Crude Oil……………………………………………………………......26

2.9.2. Paraffin (Wax)……………………………………………………………….......27

2.9.3. Corrosion/Erosion…………………………………………………………........28

2.10. Estimated quantities of separated fluid

2.10.1. Crude Oil……………………………………………………………………....28

2.10.2. Separated Water………………………………………………………….......29

2.10.3. Gas…………………………………………………………………………......29

2.11. Measurement of Effluent Fluid Quality…………………………………........30

CHAPTER THREE: OIL AND GAS SEPARATION THEORY

3.1. Factors that Influences the Efficiency of a Separation Process

3.1.1. Particle Size……………………………………………………………….........31

3.1.2. Gas Velocities………………………………………………………………......31

3.1.3. Gas and Liquid Density……………………………………………………......31

3.1.4. Operating Pressure………………………………………………………........31

3.1.5. Operating Temperature……………………………………………………....32


Mamudu Angela Onose Page viii

3.1.6. Surface Tension……………………………………………………………....32

3.1.7. Number of Stages………………………………………………………….....32

3.1.8. Stain /Handkerchief Test………………………………………………….....32

3.2. Principles Used in the Separation of Oil from Gas

3.2.1. Centrifugal Force…………………………………………………………......32

3.2.2. Density Difference (Gravity Separation)…………………………………...34

3.2.3. Filtering …………………………………………………………………….....35

3.2.4. Coalescence ……………………………………………………………….....35

3.2.5. Impingement ……………………………………………………………….....36

3.2.6. Change in Flow Direction…………………………………………………....36

3.2.7. Change in the Velocity of the Flow ………………………………………...36

3.3. Principles Used in the Separation of Gas from Oil

3.3.1. Heat………………………………………………………………………….....37

3.3.2. Settling………………………………………………………………………....38

3.3.3. Agitation……………………………………………………………………......38

3.3.4. Baffling………………………………………………………………………....38

3.3.5. Chemicals………………………………………………………………….......38

3.4. Improvement on the Gas-Liquid Separation Technology

3.4.1. Gas Liquid Cylindrical Cyclone …………………………………………......38

3.4.2. Diverging Vortex Separators…………………………………………….......40

3.4.3. Gas Scrubbers ………………………………………………………..........41

3.5. Subsea Separation

3.5.1. Factors Considered During the Designing Stage……………………........42

3.5.2. Features of a Subsea Separator………………………………………….....43

3.5.3. Advantages of Subsea Separation…………………………………….........43

3.5.4. Potential Drawbacks of Subsea Separation……………………………......44

3.6. The Subsea Separation Concept

3.6.1. Disposal of the Produced Water………………………………………….....45

3.6.2. The Subsea Sand Handling System…………………………………….......45

3.7. Application of Subsea Separation System

3.7.1. Case 1: Tordis Subsea Separation Boosting and Injection System…......46

3.7.2. Case 2: The Troll C Separation System………………………………….....47

3.8. Inline Separation Technology

3.8.1. Advantages of Inline Separation Technology…………………………......49

3.8.2. Inline Gas – Liquid Separation……………………………………………....49

3.8.3. Inline Liquid -Liquid Separation…………………………………………......54


Mamudu Angela Onose Page ix

3.8.4. Inline Sand Separation…………………………………………………….....54

3.9. Pipe Separations……………………………………………………………...55

CHAPTER FOUR: SOLID SEPARATION, DISPOSAL & HANDLING SYSTEM

4.1. Background Study…………………………………………………………....56

4.2. Sources of Solids

4.2.1. Natural Source………………………………………………………………...56

4.2.2. Artificial source……………………………………………………………......56

4.3. The Effects of Produced Sand……………………………………………...57

4.4. Techniques Used in the Disposal of Sand

4.4.1. Production Limit ……………………………………………………………....57

4.4.2. Convectional Exclusion Methodology……………………………………....58

4.4.3. Inclusion Methodology…………………………………………………….....61

4.5. Integrated Sand Cleanout System

4.5.1. Structure and Principle…………………………………………………….....61

4.5.2. Mode of Operation…………………………………………………………....61

4.5.3. Sand Transportation Behaviour…………………………………………......63

4.5.4. Effect of Sand Interference Settling……………………………………......63

4.5.5. Effect of Sand Particle Shape…………………………………………….....63

4.6. Desander (Solid Liquid Hydro Cyclone)

4.6.1. Types of Desander …………………………………………………………..64

4.6.2. Selections and Applications of Desanders ……………………………......65

4.6.3. Components of a Desander………………………………………………....66

4.6.4. Mode of Operation of a Desander ………………………………………....66

4.7. Description of a Surface Facilities Sand Handling System

4.7.1. Separation……………………………………………………………………...67

4.7.2. Collection……………………………………………………………………....67

4.7.4. Dewatering………………………………………………………………….....67

4.7.5. Haul-aging……………………………………………………………………..68

4.8. New Generation De-sander System………………………………………..68

4.8.1. Features………………………………………………………………………..68

4.8.2. Mode of Operation…………………………………………………………....68

CHAPTER FIVE: SUITABILITY OF THE TYPES OF TECHNOLOGY

5.1. Rational Criteria for Gas/Oil/Water/Sand Separation…………………......71

5.2. The Separation of Oil from Gas


Mamudu Angela Onose Page x

5.2.1. Vertical Separator…………………………………………………………......71

5.2.2. Horizontal Separator……………………………………………………….....72

5.2.3. Spherical Oil and Gas Separators…………………………………………...72

5.2.4. Gas Liquid Cylindrical Cyclone……………………………………………....72

5.2.5. Gas Scrubbers………………………………………………………………...73

5.2.6. Subsea Water Separation Plant & Integrated Solid Handling System......73

5.2.7. Inline Separation Technology…………………………………………….....73

5.2.8. Pipe Separation Technology………………………………………………...73

5.3. The Separation of Solid and Other Extraneous Material

5.3.1. Production Limits Principle …………………………………………………..73

5.3.2. Conventional Exclusion Technology…………………………………….....74

5.4. Methodologies Used By Companies for the Disposal of Sand

5.4.1. Case Study One……………………………………………………………....74

5.4.2. Case Study Two ……………………………………………………………...80

5.4.3. Case Study Three …………………………………………………………....87

5.4.4. Case Study Four……………………………………………………………...88

CHAPTER SIX: CONCLUSION AND RECOMMENDATION

6.1. Conclusion………………………………………………………………….....91

6.2. Recommendations

6.2.1. Subsea Separation Technology………………………………………….....93

6.2.2. Inline Separation Technology…………………………………………….....93

6.2.3. Pipeline Separation Technology…………………………………………....93

APPENDIX

SECTION A: Basis for Re-Entrainment in Separators

A.1. Definition and Occurrence…………………………………………………...94

A.2. Mechanisms for the re – entrainment of liquid

A.2.1. Low Reynolds Number Regime NRef<160………………………………...95

A.2.2. Transition Regime 160≤NRef ≤1635………………………………………..95

A.2.3. Rough Turbulent Regime NRef >1635……………………………………..95

SECTION B

School of Engineering Assessment Form………………………………………...96

List of References……………………………………………………………………98


Mamudu Angela Onose Page xi

LIST OF FIGURES

FIGURE HEADING PAGE

1.1: Classification of Components Found In Wellhead Fluid….......................1

1.2: Curve for Development Ranking Of Separation Technology………........3

2.1: Classification of Separators…………………………………………….........6

2.2: Gas-Oil Separator Train…………………………………………………........7

2.3: Schematic Diagram of a Three Phase Vertical Separator…………..........8

2.4: Schematic Diagram of Horizontal Three Phase Separator…………........9

2.5: Spherical Separator………………………………………………………....10

2.6: Main Equipment for a Test Separator…………………………………......11

2.7: Stage Separator Flow Diagram………………………………………….....12

2.8: Typical Horizontal Two- Barrel Filter Separator…………………………..14

2.9: Two Phase and Three Phase Vertical Separator…………………….......15

2.10: Schematic Outline of the Main Component in a Gas-Oil Separator…...16

2.11: Vane-Type Extractor with Corrugated Plates……………………………..19

2.12: Knitted Wire Mist Extractor………………………………………………….20

2.13: Blade Type Mist Extractor…………………………………………………...20

2.14: Centrifugal Mist Extractor…………………………………………………...21

2.15: Outlet Vortex Breaker………………………………………………………..21

2.16: Inlet Diverters………………………………………………………………...22

2.17: Horizontal Separator Fitted With Sand Jets and Inverted Trough……..22

2.18: De-Foaming Plates………………………………………………………….23

3.1: Centrifugal Forces Acting On a Particle in A Gas Stream……………...33

3.2: Forces Acting On A Particle in A Gravity Settling Chamber……………34

3.3: Coalescing Process in the Media…………………………………………36

3.4: The Principle of Impingement, Change Of Direction and Velocity........37

3.5: Two-Step Mechanism of Separating Gas from Oil………………………37

3.6: Gas-Liquid Cylindrical Cyclone Configuration………………………….39

3.7: Vertical Three Phase Separator acting on Centrifugal Force………….40

3.8: Diverging Vortex Separator………………………………………………...40

3.9: Centrifugal Gas Scrubber…………………………………………………..41

3.10: Subsea Water Separation Plant with an Integrated Solid Handling......42


Mamudu Angela Onose Page xii

3.11: Tordis Subsea Separation System………………………………………...46

3.12: Process Overview of the Tordis SSBI…………………………………......47

3.13: Troll C Pilot Separation Plant……………………………………………….48

3.14: Troll C Sand Removal System……………………………………………...49

3.15: Gas Unie TM…………………………………………………………………...50

3.16: Inline Phase Splitter Gas- Liquid Separation Technology……………….50

3.17: Schematic Representation of a Degasser…………………………….......51

3.18: Schematic Representation of a De-Liquidiser…………………………….52

3.19: Inline Demister Spiraflow……………………………………………………52

3.20: Inline De-liquidiser BP-ETAP……………………………………………….54

3.21: Key Advantage of Inline Liquid- Liquid Separation……………………….54

3.22: Inline Sand Separation………………………………………………………55

3.23: Pipe Separation Concept……………………………………………………56

4.1: Wire Wrapped Screen…………………………………………………….....59

4.2: Expandable Sand Screen Construction……………………………….......59

4.3: Metal Mesh Screen Assembly………………………………………………60

4.4: Open Hole Gravel Pack……………………………………………………..60

4.5: Schematic of the Surface Subsystem…………………………………......62

4.6: Schematic of the Underground Subsystem…………………………........62

4.7: Schematic of the Vessel Style De-Sander……………………………......64

4.8: Liner Style De-Sander……………………………………………………….65

4.9: Dewatered Solids Removal………………………………………………....67

4.10: Decision Diagram Showing -Outline of Solids- Handling System….......70

4.11: Solids Collection Vessel……………………………………………………..69

4.12: An Educator…………………………………………………………………..69

5.1: Sand Handling System for Exxon Company U.S.A………………………76

5.2: Schematic Diagram for the Separator of Exxon Company……………...78

5.3: Schematic Diagram for the Sand Washer…………………………………79

5.4: Process Layout of Oil and Gas Water De-Sanders……………………....81

5.5: Sand Accumulation in Production Separator……………………………...87

A.1: General Multiphase Flow- Regime Map…………………………………...94


Mamudu Angela Onose Page xiii

LIST OF TABLES

TABLE HEADING PAGE

2.1: Comparison of Oil and Gas Separators…………………….....................17

2.2: Estimated Quality of Separated Crude Oil………………………………..29

2.3: Estimated Quality of Separated Water……………………………………29

2.4: Estimated Quality of Separated Gas……………………………………...30

2.5: Measurement of Effluent Fluid Quality……………………………………30

3.1: Separator Vessels Dimensions -Different Separator Concept…………45

3.2: Characteristics of Gas/Liquid Separation Equipment…………………...53

4.1: Physical Properties of Natural Solids……………………………………..56

4.2 Physical Properties of Artificial Solids…………………………………….57

4.3: De-Sander Selection Criteria………………………………………………64

5.1: Problems & Solution for Grand Isle Block 73 A-D Platform…………….80

5.2: Operating Parameters of South Pass 78 De-Sanders………………….82

5.3: Purge Rate/Liquid Loss of South Pass 78 De-Sanders………………...83

5.4: Problems and Solutions on the South Pass 78 Field…………………...85

5.5: De-Sanding System Specification………………………………………...88

5.6: Physical and Production Parameters of Dagang Oil Well……………...88

5.7 Designed Operation Parameters of Dagang Oil Well…………………...89

A.1 Re- Entrainment Criteria for Maximum Gas………………….................89


Mamudu Angela Onose Page xiv

LIST OF SYMBOL AND NOTATION

Chapter One: Introduction

C1 Methane

C2 Ethane

C3 Propane

C6 Hexane

C7 Heptane

Chapter Two: Fundamentals of a Separating Process

GOR Gas-Oil Ratio

psi Pounds Per Square Inch

ft. Feet

FWKO Free Water Knockout

GLR Gas-Liquid Ratio

ASME American Society of Mechanical Engineer

Psig Pounds per Square Inch Gauge

> Greater than

µm Micrometre

in. Inch

≥ Greater Than or Equal to

% Percentage

𝜂𝑚𝑒𝑠𝑕 Separation Efficiency of a Mesh Pack (dimensionless)

𝜂𝑣𝑎𝑛𝑒 Separation Efficiency of a Vane Pack (dimensionless)

𝜂𝑇 Target Collection Efficiency of a Single Wire (dimensionless)

𝑒𝑠𝑝 Exponential

𝑉𝑇 Terminal Velocity (𝑚𝑠−1)

𝑚 Number of Bends

𝑊 Width of a Vane Baffle

𝑉𝐺 Gas Velocity 𝑚𝑠−1)

𝑏 Space between Adjacent Vane Blades (m)

𝐶𝐷 Drag Coefficient

𝜌𝐺 Gas Density (𝑘𝑔𝑚−3)

𝑉𝐴 Actual Gas Velocity (𝑚𝑠−1)

𝐴𝑃 Projected Area of a Vane Blade (𝑚2)


Mamudu Angela Onose Page xv

𝐴𝐶 Cross Sectional Area of a Vane Pack (𝑚2)

∆𝑃𝑣𝑎𝑛𝑒 Pressure Drop across Vane Pack (Pa)

𝐻 Thickness of Mesh Pad (m)

ԑ Void Fraction of a Mesh Pad (dimensionless)

PVC Polyvinyl Chloride

gal Gallon

MMscf Million Standard Cubic Feet

mm Millimetre

𝑅𝐸 Droplet Reynolds Number (dimensionless)

𝑑 Circular Pipe Diameter (m)

𝑣 Velocity (𝑚𝑠−1)

𝜌 Density (𝑘𝑔 ⁄ 𝑚^3 )

𝐻𝑅 Hydraulic Radius

𝑊𝑃 Wetted Perimeter

API American Petroleum Institute

Of Degree Fahrenheit

cP Centipoise

BS&W Basic Sediment and Water

ppm Parts per Million

Chapter Three: Oil-Gas Separation Theory

𝑆𝐶 Separator Capacity

𝜌𝐿 Density of Liquid (𝑘𝑔 ⁄ 𝑚^3 )

𝜌𝑔 Density of Gas (𝑘𝑔 ⁄ 𝑚^3 )

sec Second

𝜋 Pi (3.14159)

𝑕 Height of Centrifuge (m)

𝑞 Volumetric Rate

𝐶𝑑 Drag (friction) Coefficient

bwpd Barrels of Water per Day

bopd Barrels of Oil per Day

bbl/D Barrels per Day

US$ United State Dollar

CAPEX Capital Expenditure

OPEX Operating Expenditure


Mamudu Angela Onose Page xvi

Chapter Four: Solid Separation, Disposal and Handling System

Si02 Silicon Dioxide

ppmv Part per Million by Volume

𝑢𝑠0 Free Ultimate Sand Settling Velocity

𝜇 Viscosity

𝑈𝑠 Terminal Settling Velocity of Particle

𝐾𝑚 Stokes Cunningham Correction Factor (dimensionless)

𝜆𝑚 Mean Free Path of Gas Molecules (ft.)

𝐷𝑝 Diameter of Spherical Particles (ft.)

𝑔𝑐 Conversion Factor, 32.17(LB. Mass/LB.Force)

Ṽ Mean Molecular Speed, ft. /sec

lbm Pound Mass

ANSI American National Standards Institute

Chapter Five: The Suitability of the Different Types of Technology and

Possible Solutions to Problems Encountered

LP Low Pressure

B/D Barrel per Day

≥ Greater Than or Equal to

DOT Department of Transportation

USD United State Dollar

MPa Mega Pascal (1000000Pa)

Kg/m3 Kilogram per Cubic Metre

Appendix

Section A: Basis for Re-entrainment in Separators

𝑁𝑅𝑒𝑓 Reynolds Film Number (dimensionless)

𝑑𝐻 Liquid Hydraulic Diameter (ft.)

𝜌𝐿 Density of Liquid (𝑘𝑔 ⁄ 𝑚^3 )

𝑁𝜇 Interfacial Viscosity Number (dimensionless)

𝑣𝐿 Velocity of liquid (ft/sec)

𝜍 Surface Tension between Liquid and Gas (lbm/𝑓𝑡3)

𝜇𝐿 Dynamic Liquid Viscosity (lbm/ft-sec)


Mamudu Angela Onose Page 1

CHAPTER ONE

INTRODUCTION

1.1. Background Study and Problem Statement

Separation technology constantly plays an important role in the distribution of

hydrocarbon from the production sites to the market and has demonstrated over

the years to be the force behind the success of any hydrocarbon production

process. From previous studies, it has been proven that 30% of the total capital

of an oil and gas production platform goes into the purchase of a separator unit-

[1].

Hydrocarbons do not rise up the oil-well alone. A typical reservoir fluid

comprises of a mixture of different hydrocarbon group, varying quantities of salt,

water and solids as shown in Fig.1.1 below. The light group consists mainly of

methane and ethane jointly referred to as the gas phase; the intermediate group

is commonly known as gasoline while the heavy group which is the largest

section constitutes the bulk of oil-[2, 3].

Fig 1.1 Classification of components found in wellhead fluid

In the early days of oil production, difficulties were being encountered in the

handling, metering and most especially transportation of this mixture to

refineries and gas plant for processing. It therefore became a necessity to

devise a means by which the separation of this fluid will be carried out in a safe

and most economical way.

HYDROCARBON SOLID

RESERVOIR FLUID

FREE

WATER

EMULSI

FIED

WATER

SAND SILT

AND

CLAY

LIGHT

GROUP

(C1/C2)

INTERM

EDIATE

GROUP

(C3-C6)

HEAVY

GROUP

(C7+)

WATER



1.2. Well Fluid Separators

The basic and most fundamental step in the processing of reservoir fluid is the

separation of its component into their distinctive phases. Due to this reason, the

separation unit is still referred to as the backbone and the heart of the

processing stage-[2, 4].

In the days of yore, separation was classified as either being simple or complex

depending on the severity of the roles they played. During this period, the well

fluid were stored in a wooden tank where the separation process was carried

out based on physical differences such as colour, size and shape. This process

had a lot of limitations especially not being able to meet the standard set by

both the refineries and the transportation facilities-[2, 3, 5].

This led to the designing of a gas-oil separation plant mainly to separate solids

from the produced hydrocarbon, refine them for easy transportation/export

facilities, and allow regular testing/metering of the distinctive phases with the

aim of meeting the standard set by both the refineries and pipeline operators-

[3].

1.3. Modifications

Formerly, separators were basically classified based on the number of phases

they encountered relying completely on the principle of gravitational settling to

carry out both their primary and secondary functions. This was carried out in a

pressure vessel that was bulky, large and very costly to operate and maintain.

This instigated the industry in the pursuit of other reliable alternatives as shown

in fig 1.2 below-[6, 7].

Additionally other mechanism/principle has also been incorporated to aid the

efficiency of the separation process. This principles include enhanced

gravitational settling, Impingement, change in the direction/ velocity of the flow,

filtration, coalescence, agitation, diffusion, scrubbing, sonic precipitation

application of heat and chemicals and most especially the use of centrifugal

force which has been applied in different Industrial practices-[8,9].



The discovery of both the Inline and pipeline separation technology has also

brought some level of satisfaction to the oil industries due to their attractive and

immeasurable benefits.

Figure 1.2: Curve for Development Ranking of Separation Technology.

Taken from-[6]. Hence this study is carried out to investigate and research on the separation

theory as a whole.

1.4. Research Intent

This study aims to investigate

The different separation technologies adopted for the separation of well

fluid in the oil and gas industry, demonstrating their suitability for different

operating condition.

The parameters that determine the effectiveness of a separation

process.

The different procedures used for the disposal and handling of solid and

other extraneous material.

The suitability of each technology discussed.

1.5. Scope of Work

The research will cover the following area.

A review on the general oil and gas separation theory; history, definition,

selection, application, operation, maintenance, classification, safety

features and functions of oil and gas separator.

Problems encountered in separators and possible solution.



The various principles used to separate the reservoir fluid into their

distinct phases.

A detailed study on subsea separation process and other new separation

technologies.

The effect of solids production on the equipment, formation and the

environment as a whole and the technologies used for their disposal

Case studies on the different methodologies adopted by various

companies, the problems faced and modification carried out

1.6. Research Justification

The result from this research can be used both in the educational and industrial

sector.

1.6.1. Educational sector

It will create more awareness on the indispensable role the separator

plays in the processing of the reservoir fluid.

It will point out the areas in which further studies can be carried on

1.6.2. Industrial sector

The different limitations and recommendation that will be outlined in the

report will come handy during the designing of a separator where

different modifications have to be implemented.

1.7. Thesis Structure

The outcome of this study is presented in the following chapters:

Chapter two generally focuses more on definitions, components, functions,

classification, importance, applications, features, operational/safety procedures

of oil-gas separators and the estimations/measurements of separated fluid. Its

operational procedure, basis/mechanism of re-entrainment and the general

problems/solutions of a separation process was also discussed in details.

Chapter three presents an in-depth analysis on the different factors that could

affect the working efficiency of a separator, the various principle/mechanism

used for the separation process, problems that occur in a separation process

and possible solutions. It also focuses on the different improvements and recent



separation technology that is currently being used in the oil industry, with case

studies were necessary.

Chapter four dwells more on the effects of solid production on the equipment’s,

formation and the environment as a whole. The various techniques used for the

handling and disposal of solids, with the focal point being the desanders.

Chapter five includes report of case studies carried out on the different

methodologies adopted by companies for solid handling. Based on knowledge

acquired, solutions will be provided to the different challenges encountered. An

outline of the different criteria’s will also be presented demonstrating the

suitability of the different technologies mentioned.

Chapter Six will outline the conclusions and lesson learnt from the thesis, also

recommending various aspect of the work that still need further research.



CHAPTER TWO

FUNDAMENTALS ON OIL AND GAS SEPARATION

2.1. The Importance of a Separating Process

The separation of the reservoir fluid is always carried out as soon as possible

due to the following reasons-[10]:

It becomes technically easier and more cost effective to process the

distinctive phases individually.

The water contains significant amount of salt which acts as a corrosion

agent; therefore removal of water from the system will help reduce the

rate of corrosion and also ensures that less expensive materials are used

for construction downstream.

Phase separation reduces the back pressure which in-turn boost the

overall output as lesser energy will be needed to transport the separated

phases.

It helps in retrieving relevant products and also boosts their qualities.

It prevents the emission of harmful gases into the environment.

2.2. Definition of Oil and Gas Separator

An oil and gas separator is a pressure vessel that relies on the large difference

in density between the gas and the other phase (oil, water, solids), to split the

multiphase mixture into distinctive phases-[9, 11].

2.3. Classification of Separators

Figure 2.1 below illustrates the general classification of oil and gas separators.

PRINCIPLE

CONFIGURATION VERTICAL, HORIZONTAL AND SPHERICAL SEPARATOR

PHASES

APPLICATION

LOW PRESSURE, MEDIUM PRESSURE AND HIGH PRESSURE

SEPARATOR

TWO PHASE UNIT AND THREE PHASE UNIT

LOW TEMPERATURE, TEST AND PRODUCTION

IMPINGEMENT, GRAVITY, COALESCENCE AND CENTRIFUGAL

FORCE

SEPARAT

ORS

OPERATING PRESSURE

Figure 2.1: Classification of Separators



2.3.1. Classification by operating pressure

Separators can generally be grouped into three, based on their operating

pressure [2]. Fig 2.2 below shows how these three groups can be positioned in

a gas- oil separator train.

Low-pressure separators: operates within the range of 20-225 psi.

Medium-pressure separators: operates within the range of 230- 700 psi.

High-pressure separators: operates within the range of 750-1,500 psi.

Figure 2.2: Gas-Oil Separator Train. Taken from-[10].

2.3.2. Classification based on configuration

Based on the structure or shapes, separators are designed in three forms

namely: Vertical, Horizontal and Spherical oil and gas separators

2.3.2.1. Vertical separators

They are regarded as the oldest and most prominent class of separator used in

the oilfield, particularly in areas where the GOR is considered low. They are

easily recognised for their upright cylindrical structure alongside their necessary

internal features where the inlet, gas and liquid outlet are always located at the

centre, top and bottom of the vessel respectively as shown in figure 2.3 below-

[5,12].

They vary in size from 10 or 12 inch in diameter, and 4 to 5ft seam to seam(s to

s) to 10 or 12ft in diameter and 15 to 25ft seam to seam-[9].



Figure 2.3: Schematic Diagram of Three Phase Vertical Separator. Taken from-[13].

The advantages and disadvantages of a vertical separator as discovered by -

[11, 14], includes the following:

2.3.2.1.1. Advantages

Best for the handling of large quantity of impurities especially sand and

mud.

Highly recommended in areas where spaces are limited.

It becomes easier to install control and safety accessories e.g. alarms,

level indicator.

They are flexible which makes them very handy.

Easier to clean and maintain.

2.3.2.1.2. Disadvantages

They are regarded as not being cost effective when compared to the

horizontal separator.

They are not suitable for the handling of foamy crude oil.

The mist extractor has a lesser drainage system when compared to that

of the horizontal separator.

Difficulties are encountered during the servicing of the top mounted

accessories.

They cannot be used in areas where the gas- oil ratio is high.



2.3.2.2. Horizontal separators

Figure 2.4 below shows a schematic diagram of a horizontal separator which

can be manufactured with either a mono tube or dual type shells.

They are basically designed to accommodate larger amount of gas, and also to

prevent any kind of agglomeration of solid. They range from 10 or 12 inch in

diameter and 4 to 5ft seam to seam up to 16ft in diameter and 60 to 70ft seam

to seam, and tend to be more effective when the system flow rate remains

constant from a clean source of well-[5, 9].

Figure 2.4: Schematic Diagram of Horizontal Three Phase Separator Courtesy “U.S. Environmental Protection Agency”.

The advantages and disadvantages - [11]of a horizontal three phase separator

include the following:


Reduced cost for service and maintenance

They can be used for the separation of foamy crude oil

It has a higher liquid capacity with a high GLR

The direction of the flow does not have any effect on the mist extractor

drainage.

The effect of turbulence is effectively handled.

The ability to handle a larger volume of oil helps to increase the retention

time.

They are less prone to freezing in the cold climate thereby increasing

both the availability and reliability.



Vessels can be stacked up together in limited spaces.

They have more surface area and higher liquid capacity has compared to

that of the vertical separator.


They are not recommended to be used in the handling of impurities.

It requires larger amount of space for installation.

At a larger flow rate, the rate of liquid entrainment increases

tremendously with an increase in the liquid level.

They tend to be more difficult during cleaning exercise.

2.3.2.3. Spherical separators

As shown in figure 2.5 below, spherical separators are ball shaped vessel that

comprises majorly of two hemispherical head. They are designed purposely to

incorporate all the known principles of separation and are applied in operations

that have low to intermediate GOR’s.

They are usually attainable in 24/30 inches up to 66/72 inches and comprise

majorly of two hemispherical head with suitable internal fittings. Little has been

known about them until recently where the advantages and general acceptance

of a spherical separator came into limelight-[5, 9, 14].

Figure 2.5: A Spherical separator. Taken from-[14] .

According to [14], the advantages and disadvantages of a spherical separator





They are more flexible than the horizontal type thereby increasing their

utility

Their compactness nature makes them easily fixed or hooked up.

They are more cost effective when compared to both the vertical and

horizontal separators

They are easy to maintain and clean

They perform better than the vertical separator when it comes to the

issue of sand drainage.


They cannot be used for a three phase (gas, water and oil) separation

process because of its inadequate internal area.

They tend to be ineffective in their mode of operation largely due to their

low liquid settling and limited surge capacity.

They are always associated with different fabrication problems.

2.3.3. Classification by application

2.3.3.1. Metering/test separator

They simultaneously carry out the function of both separating and metering the

well fluid. Under stable condition, a test separator as shown in figure 2.6 carries

various tests to evaluate the quality of both the oil and gas using a turbine meter

and an orifice meter respectively. These tests are usually carried out at an

interval of every 24hours-[2, 9].

Figure 2.6: Main Equipment for a Test Separator. Taken from-[2].



2.3.3.2. Low temperature separator

This is a unique type of separator that works under the principle of temperature

reduction, which is acquired by the Joule-Thomson effect of expanding the

reservoir fluid. Its major function is to separate the light hydrocarbon from the

gas stream-[2].

2.3.3.3. Elevated separator

They are installed on offshore platforms for an easy flow of liquid from the

separator, into the downstream storage. It operates at its lowest possible

pressure, thereby bringing about a reduction in the evaporation of gases into

the atmosphere. This helps to capture the maximum amount of liquid-[9].

2.3.3.4. Production separator

They range in length from 6 to 70ft, and separate the production well from a

group of wells on a daily basis. They can also be used for a two or three phase

system-[9].

2.3.3.5. Foam separator

They are specially designed to handle the issue of foaming in the separation

process-[9].

2.3.3.6. Stage separators

This is usually applicable in areas where the reservoir fluid has to flow through

different stages of separation during its processing phase as shown in figure 2.7

below-[9].

Figure 2.7: Stage separator flow diagram. Taken From-[2].



2.3.4. Classification based on their function

2.3.4.1. Trap/stage separator

This is the most predominant type of separator installed in areas where high

peak of flow is encountered which might require slug handling. These areas

includes producing lease (Platform near the wellhead manifold) or tank battery

(tanks connected together to receive crude oil production from the well)-[9].

2.3.4.2. Knockout vessel

This is applied in areas where separation of water only is needed. There are

two common types namely: The free water knockout (FWKO) and the total

liquid knockout. The free water knockout first separates the three phase mixture

from the well fluid, and then removes the water for treatment and proper

disposal. The total -liquid knockout works frequently with a cold separation unit

and concentrates more on the removal of liquid above the operating pressure of

3000psig-[9,10].

2.3.4.3. Flash chamber, flash vessel or fish trap

This operates at a low pressure and is frequently used as a second stage

separator on a cold separation unit-[10].

2.3.4.4. Expansion vessel

It is also called a cold/low temperature separator because of its inner heating

coil. Its basic function is to melt and handle hydrates that are formed within the

system and operates within the range of 1000-1500 psig - [9, 10].

2.3.4.5. Gas scrubber

They are more efficient than the general separators in detaching the liquid from

the vapour phase. They are located before the compressors, glycol and amine

unit and are used downstream of the separator to help reduce the rate of liquid

entrainment in the gaseous phase. They are frequently found in gas gathering,

sales and distribution lines where handling of large amount slugs will not be

necessary-[9, 10].

2.3.4.6. Gas filter, dust scrubber, or coalescer

The removal of dust, line scales, rust, fogs and other foreign material from the

gas stream is done via a filtering medium. They are often referred to as the final

cleaning stage. The filter fibre traps the solids while the liquid droplets are



coalesced into larger droplet and then separated by the force of gravity-[9, 10].

A filter separator is shown in figure 2.8 below

Figure 2.8: Typical horizontal two- barrel filter separator taken from-[8].

2.3.5. Classification based on the number of phases

2.3.5.1. Two phase unit

Its function is to separate gas from oil in an oil field, or gas from water in a gas

field. [2]

2.3.5.2. Three phase unit

This further separates the gas from the liquid phase, and water from oil. Due to

the difference in density, the oil and water will separate amicably, where the

water and the oil flows to the bottom and the top respectively. The Spill over

weir interface and the Oil bucket weir/plate then helps to regulate the quantity

of the separated liquid.

Spill over weir interface control: ensures that the water and the oil flow

to the upstream and the topside of the weir respectively. It has its

advantages of having a lower retention time (three minutes) and being

more cost effective compared to the oil bucket weir approach-[9].

Oil bucket and weir plate. This uses the difference between the specific

gravity of the liquid and the ―head‖ of the liquid to ensure that water and

oil are discharged in different compartments where they can easily be

collected. [6] Although this process tends to be very effective, it requires

a more retention time and internal baffling-[9]



Figure 2.9: Two Phase and Three Phase Vertical Separator. Taken from-[10].

2.3.6. Classification by principle

Separators can also be grouped based on the mechanism behind the

separation process. This includes: difference in gravity/density, impingement,

coalescence, centrifugal force, scrubbing, diffusion, electrical precipitation,

sonic precipitation and thermal separation.

2.4. Common Component of Oil and Gas Separator

Figure 2.10 below illustrates the four major compartments in an oil and gas

separator that collectively works together to carry out both their primary and

secondary function. These various sections include:

2.4.1. Primary phase separation section

Their function is to remove large quantities of the liquid from the inlet stream,

control the rate of gas turbulence and momentum of the fluid at the inlet stage,

and reduce the formation of slugs plus liquid particles being re- entrained into

the gaseous phase. Its processes are usually carried out with the aid of a well-

shaped deflector plate, centrifugal force and a change in the direction of the

flow - [2, 5, 9].

2.4.2. Secondary/ gravity settling section

This section ensures that both the liquid/gas flow rate is within the range of the

maximum superficial velocity. Gravity settling allows smaller liquid droplets to be

captured and removed while the internal baffles assist in reducing the rate of



turbulence by breaking foams produced. The degree of effectiveness of this

section depends on the properties of the fluid, the liquid drop size and the

degree of turbulence-[2, 5, 9].

2.4.3. Mist extraction or coalescing section

This section uses an impingement surface, mist extractor or centrifugal force to

guarantee the removal of minute liquid droplet (>100µm) from the gas stream-

[5, 9].

2.4.4. Liquid accumulation section

They ensure that entrainment from both the liquid and vapour phase do not

occur by providing adequate retention time. This stage is configured in such a

way that the separated liquid has little or no disturbances from the flowing gas

stream, have a liquid level control and enough capacity for the handling of

surges-[2, 5, 11].

Fig 2.10: Schematic Outline of the Main Component in a Gas-Oil Separator. Taken From-[2].

The other compartments that also help to ensure a safe and effective

separation process include the following:

2.4.5. Process controls

They basically perform two major roles namely: to assist in stabilizing the

pressure within the system via a back pressure regulator located in the exit gas

line or to use a compressor suction control to prevent pressure loss across the

valves. Liquid level controllers in combination with internal baffles and weir are

also used to regulate the liquid level in a separator-[10].



2.4.6. Safety devices

It is a major requirement from the ASME that both relief valves and rupture

disks should be installed on a separator serving as pressure relief apparatus

during emergency periods-[10].

2.5. Comparison of the Pros and Cons of Oil and Gas separators

Table 2.1 below illustrates certain factors that should be taken into

consideration when comparing the different types of separators.

Table 2.1: Comparison of Oil and Gas Separators. Taken from-[2] .

Considerations Horizontal Vertical Spherical

Location of inlet and outlet

stream

Efficiency of separations

1 2 3

Stabilization of separated

fluids

1 2 3

Adaptability of varying

conditions

1 2 3

Flexibility of varying

condition

2 1 3

Capacity (same

diameter)

1 2 3

Cost per unit capacity

1 2 3

Ability to handle foreign

material

3 1 2

Ability to handle

foaming oil

1 2 3

Adaptability to portable use

1 3 2

Ease of installation

1 3 2

Ease of inspection and maintenance

3 1 2



Space required for installation

Vertical 2 3 1

Horizontal 1 3 2

1. Most favourable; (2) Intermediate; (3) Least favourable

2.6. Internal Components of Gas-Oil Separators

2.6.1. Mist extractors

Although the principle of gravitational settling is adopted in separating the liquid

phase from the gaseous phase, a mist extractor also helps to enhance the

separation process by removing completely all liquid mists from the vapour

phase. The common types of mist extractor include:

2.6.1.1. Vane type extractors

They frequently use a Dixon plate to carry out their objective. Dixon plates are

flat plates spaced at an interval of 1 in. from each other, positioned parallel to

the flow of the gas and also inclined at an angle of 45 degree to the horizontal

surface.

As illustrated in figure 2.11 below, the gas is allowed to flow through these

plates thereby reducing the rate of turbulence within the system and also

decreasing the vertical distance a droplet of liquid has to fall due to gravity

before it is being collected-[10].

The efficiency of this extractor depends on the numbers of the vanes used,

distances between the vanes, diameter of the liquid particle to be removed,

distances between the drainage systems and the total number of the drainage

system use-[9].

2.6.1.1.1. Features

The features of a vane type extractor-[10] are:

They are very economical and are not prone to foul or any other foreign

material.

They can remove all entrained liquid droplet with a diameter of ≥8μm.

They are also capable of removing 99.5% of all particles with a diameter

≥ 1.0um



The collection efficiency and the pressure drop across a vane type extractor-

[15] can be derived from equation 2.1 and 2.2 respectively.

𝜂𝑚𝑒𝑠𝑕 = 1 − 𝑒𝑠𝑝 −𝑉𝑇 . 𝑚. 𝑊. 𝜃

57.3. 𝑉𝐺 . 𝑏. 𝑡𝑎𝑛𝜃 ⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛2.1

∆𝑃𝑚𝑒𝑠𝑕 = 1.02 × 10−3 𝐶𝐷 .𝜌𝐺𝑉

2𝐴 . 𝐴𝑝

2𝐴𝑐⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛2.2

Figure 2.11: Vane-Type Extractor with Corrugated Plates and Liquid

Drainage Trays. Taken from-[13] .

2.6.1.2. Fibrous/knitted wire mesh mist extractor

History has it that fibrous mist extractor as shown in figure 2.12 below has been

used as early as the 1950’s to handle the separation of larger amount of liquid

mist from the gas stream.

They are basically designed by intertwining wires within a diameter range of

0.002-0.020in, which makes them more flexible and structurally sound-[9, 10,

13].

2.6.1.2.1. Features

The features of a vane type extractor-[10] are listed below:

They are designed to remove fine droplet within the range of 10 - 100μm

from a stream of gas.

They become very effective when used for a clean inlet stream where the

tendency for plugging is very low.

They have a low cost of maintenance as compared to the other types.



They come in different variation namely: carbon, stainless steel, nickel,

aluminium or plastic.

Figure 2.12: Knitted Wire Mist Extractor, Courtesy “Knitwire Products”

The collection efficiency and the pressure drop across the wire mist extractor

can also be derived from equation 2.3 and 2.4 respectively-[15].

𝜂𝑣𝑎𝑛𝑒 = 1 − 𝑒𝑥𝑝 −2

3𝜋. 𝐴. 𝐻. 𝜂𝑇 ⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛2.3

Δ𝑃𝑣𝑎𝑛𝑒 =𝑓. 𝐻. 𝐴. 𝜌𝐺𝑉

2𝐺

981𝜀2⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛2.4

2.6.1.3. Blade type mist extractors

This design incorporates the principle of impingement, change in the

direction/velocity of the gas, and coalescence flow to reinforce the removal of

liquid droplets. The plates can be designed with carbon/stainless steel, PVC or

polypropylene and are spaced at an interval of 0.5-3 in.

They are known basically for their excellent performance (>90%) in removing

liquid droplet larger than 10mm and an entrainment loss of 0.1 gal/MMscf,

provided the drainage of the liquid occurs at right angle to the direction of the

gas flow as shown in figure 2.13-[10].

Figure 2.13: Blade Type Mist Extractor. Taken from-[11].



2.6.1.4. Micro fibber extractor

They are made from very small densely packed fibers with an average diameter

of less than 0.02mm and are used basically to capture minute droplet of liquid.

There are two major variations namely the diffusion and impaction micro fibber

units-[13].

2.6.1.5. Centrifugal mist extractors

Its ability to operate on centrifugal force makes it unique and different from the

others. Albeit it is more effective and less prone to plugging, it is whimsically

used because of its performance susceptibility to little changes in flow rate and

its requirement of large pressure drop to establish the centrifugal force-[1, 13].

Figure 2.14: Centrifugal Mist Extractor .Taken from-[13] .

2.6.2. Vortex breaker

A vortex can be described as a motion of a fluid spinning around its centre,

caused majorly by a poor design of the outlet side which results in a significant

amount of liquid carry –over and gas slippage. It is not easily detected which

leads to an extreme pressure drop, thereby reducing the efficiency of the

separation process-[10].

Figure 2.15: Outlet Vortex Breaker Designs. Taken from-[10].



2.6.3. Wave breakers

There is a high tendency of wave occurring at the gas-liquid interface in a long

horizontal separator. This affects the performance of the separator negatively

as it produces unstable variation in the liquid level. This phenomenon can be

avoided by the installation of a wave breaker which comprises of vertical baffles

positioned perpendicular to the direction of the flow-[2].

2.6.4. Inlet diverters

They provide a means of creating a sudden and swift change of momentum at

the inlet which leads to a massive separation of the liquid from the vapour

phase. There are two types of an inlet diverter namely: Baffle plate diverter and

the centrifugal diverter. The baffle plate diverters are frequently used in the

industry and can assume the shape of a flat plate, spherical dish or a cone as

illustrated in figure 2.16. Although the centrifugal diverter is more productive, it

is very expensive and not affordable by everyone-[2].

Figure 2.16: The Two Types of Inlet Diverters. Taken from-[13] .

2.6.5. Sand jets and drains

The production of sand has been known to negatively affect the efficiency of a

separator as it utilises significant volume of space. Although a vertical separator

is designed to handle the disposal of solid, a horizontal separator that is

implemented with sand jets and drains as seen in figure 2.17 below can help in

discharging the agglomerated sand-[2].

Figure 2.17: Schematic of a Horizontal Separator Fitted With Sand Jets and Inverted Trough. Taken From-[8] .



2.6.6. De-foaming plates

Foaming produces tiny spheres (bubbles) of gas which are enveloped in a thin

film of oil. This occurrence affects the efficiency of any separator as it occupies

spaces that would otherwise have been used for the separation process, disturb

the general operation of the level controller, and if allowed to grow might lead to

the flowing of liquid alongside the vapour phase (liquid carry over).

This can be dealt with by introducing arrays of inclined closely spaced parallel

plate as illustrated in figure 2.18. As the foam passes through the plates,

amalgamations of bubbles take place thereby separating the liquid from the

gas-[2, 9].

Figure 2.18: De-foaming plates taken from-[10] .

2.7. The Operational Procedure of Oil and Gas Separators

The separator carries out its duties often in three stages namely: the primary,

secondary and the final segregation stage.

2.7.1. Primary stage

The inlet steam that enters the vessel is a combination of both the liquid and the

gaseous phase. They come in from the flow line with a high momentum which

has to be reduced or controlled at the separator inlet. The momentum absorber

and the inlet diverter produces controlled directional acceleration for the

incoming fluid thereby allowing natural gravitational separation process to take

place-[11].

At the downstream of this momentum absorber, the liquid phase with the

entrained gas will be separated while above it, the separation of the gaseous



phase with the entrained liquid will also take place. The design of this

momentum absorber varies on the configuration of the separator and the

operating condition of the flow-[11].

2.7.2. Secondary stage

The main objective of this stage is to provide a gas free liquid phase and liquid

free gas phase for a given set of operational conditions in the smallest possible

vessel. This is achieved by the use of closely inclined baffle plates which helps

to reduce the rate of agitation within the fluid and also to drain any foam that

has already being formed. [11]

The size of the vessel is an economic factor that has to be considered in regard

to both the final user and the manufacturer. The degree of turbulence should

also be monitored as excessive agitation could negatively affect the diameter of

the particle-[11].

The degree of turbulence can be measured from the dimensionless Reynolds

number as shown in equation 2.5

𝑅𝐸 =𝑑𝑣𝜌

𝜇 ⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛 2.5

Where v is the velocity of the fluid, ρ is the density of the flowing fluid, while d is

the circular pipe diameter which can be derived from equation 2.6

𝑑 = 4 × 𝐻𝑅 ⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛 2.6

HR is the hydraulic radius which can also be calculated from equation 2.7

𝐻𝑅 = 𝐴/𝑊𝑃⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛 2.7

A is the cross sectional area while WP is the wetted perimeter.

2.7.3. Final segregation

Assuming that all design conditions are met, both the liquid and the gas phase

will leave the separator without any form of re-entrainment, but this is not

always the usual occurrence as re- entrainment tends to build up when there is

accumulation of bubbles, an increase in the exit velocities or the presence of



dry gas within the system. A separation process is therefore said to be over

when the liquid entrained gas phase filters through the mist extractor.

Water jets and any other form of desanders are also located at the bottom of

the vessel that helps to handle the disposal of solids. Vortex breaker which is

located above the oil outlet helps to avoid the re- entrainment of gas into the

liquid phase. Therefore the location and designing of a good vortex control is

very paramount-[11].

NOTE: The basis for re- entrainment in separators can be seen in details

in section A of the appendix.

2.8. Maintenance Procedures for Oil - Gas separators

2.8.1. Periodic Inspection

In refineries plant, it’s a general practise to prevent erosion and corrosion from

occurring by inspecting the pressure vessels and the pipe works at regular

interval. In the oil field, this law does not apply as equipment’s are only being

replaced when an actual failure takes place, creating an unsafe working

environment for personnel-[9].

On a general note oil and gas separator should be installed far away from other

equipment’s so as to prevent severe damage to both personnel and

surrounding equipment in the event of failure of valves or other safety

accessories. Safety relief devices should be installed at close proximity in a

way that the reaction force from exhausting fluid does not unscrew, break off or

dislodge the safety devices. [9]

The following safety features are included in the designing of a separator-[9].

2.8.1.1. High and low liquid level control

This are float operated pilots that activate a bypass valve, strike a warning

alarm in order to stop any damage that might occur as a result of low liquid

level-[9].

2.8.1.2. High and low pressure control

These controls can be mechanical, pneumatic or electrical and helps to

regulate the pressure within the system-[9].



2.8.1.3. High and low temperature control

They also help to regulate the operating temperature within the desired value.

Separators should always be operated above the hydrate formation

temperature to avoid the formation of hydrates-[9].

2.8.1.4. Safety heads (rupture disk)

This apparatus has a thin metal covering that breaks apart when the designed

pressure in the separator has been exceeded. A separator should not be

allowed to function, except it has a properly fitted safety head-[9, 10].

2.9. Operational Problems in Separators

There are several operating problems that could occur in a separator system;

they are briefly discussed below.

2.9.1. Foamy crude Oil

This is a major factor that could greatly affect the efficiency and reliability of any

separators. Foaming is the production of tiny spheres (bubbles) of gas

enveloped in a thin film of oil, caused majorly by the disturbances within the

flow.

Crude oil is more likely to foam at an API gravity of >40o, operating temperature

of > 160Of, with a viscosity value greater than 53cp. They occur mainly at the

top of the riser or at the gas/liquid interface and tend not to be stable for a long

period of time unless a foaming agent is present-[9].

2.9.1.1. The effect of foaming

The effect of foaming-[9], on both the operations and efficiency of a separator


A longer retention time will be required to satisfactory separate a given

quantity of foaming crude oil. This leads to a decline in the efficiency of

the separation process.

Foaming crude oil cannot be measured accurately.

There is the tendency for a potential loss of oil and gas due to its

improper separation technique.

2.9.1.2. Solutions

The solutions to a foamy crude oil- [11] include the following:



The application of silicones and other suitable foaming depressant

chemical can help reduce the foamy surface area, foam stability and

retention time which are the controlling parameters for foam formation.

A good separator design can also help control the level and rate of foam

formation.

A large separator design that has enough retention time can assist in

breaking the formed foam without the application of any chemical.

2.9.2. Paraffin (Wax)

Waxes can be defined as high molecular weight paraffin’s (C17+) that get to

coagulate from crude oil. The deposition of paraffin fills the vessel thereby

obstructing both the work of the mist extractor and the flow of the fluid. This

leads to a decline in the efficiency of the separator and ultimately leads to loss

in production-[9].

2.9.2.1. Solutions

[11] stated the following ways by which paraffin can be removed from crude oil.

The temperature of the oil should be kept below its cloud point which is

the point at which wax starts to form

The use of centrifugal mist extractor could also help.

2.9.3. Corrosion/Erosion

The presence of hydrogen sulphide and carbon dioxide renders the reservoir

fluid corrosive. They cover up to 40-50% of the size of the gas which reduces

the efficiency of the separator. Erosion occurs due to liquid droplet and solid

particle impingement, which becomes more pronounced with the production of

sand-[9].

2.9.4. Sand, silt, mud and salt

The production of solids alongside the reservoir fluid has a negative impact both

on the quality of the product and the efficiency of the separators itself. If left to

accumulate in the separator for a long time can lead to erosion, corrosion and

even damages in the formation. They can be removed upstream of the

separator via a sand jetting system, plate interceptors or at regular interval,

digging the sand out of the system-[16].



2.9.5. Carry over and Blow-by

Liquid carry over is defined as the entrainment of liquid into the separated

vapour phase while blow by is the entrainment of vapour into the separated

liquid phase. This occurrence depends on the vessel shape and its operating

condition which reduces the overall performance of the separation process-[15].

Liquid carry over can be reduced or eliminated with the use of a mist eliminator

which is usually 100mm to 150mm thick. They help to coalesce smaller liquid

droplets into larger drops that can easily drain into the liquid phase. The vortex

breaker also helps to reduce the amount of gas flowing with the oil or the

condensate-[15].

2.9.6. Emulsions

Oil- water emulsion affects the efficiency of a separator by reducing the

available volume needed for the separation of water droplets. It also increases

the BS&W level in the oil leaving the separator. The effect can be reduced by

applying emulsion breaking chemicals upstream of the separator-[17].

2.9.7. Hydrates

These are ice- like solid crystals formed in the presence of a water/gas

interface, cold temperature, and some degree of agitation. Its formation occurs

in the ratio of 85% water to 15% hydrocarbons. Their ability to increase at a

very fast rate makes it easier for them to block flow lines and the process

equipment as a whole-[17].

They can be reduced or totally eradicated by drying the water with tri- ethylene

glycol, maintaining high temperature or by the addition of hydrate inhibition

chemicals such as methanol (MeOH), mono ethylene glycol (MEG) or tri

ethylene glycol-[17] .

2.10. Estimated quantities of separated fluid

2.10.1. Crude Oil

Table 2.2 below illustrates the amount of free gas and water content that can be

separated from crude oil under average field condition. It should be noted that a



significant amount of gas and water will still be left in the separators, except

factors like its configuration and operating parameters are put into

consideration.

Table 2.2: Estimated Quality of Separated Crude Oil. Taken From-[9] .

APPROXIMATE OIL

RETENTION TIME(MINUT

ES)

ESTIMATED FREE (NON

SOLUTION) GAS CONTENT OF

EFFLUENT OIL (%) *

ESTIMATED RANGE OF WATER CONTENT OF EFFLUENT OIL

Minimum

Maximum

Minimum(ppm)

(%)**

Maximum(ppm)

(%)**

1 to 2 5 20 16000 1.6 80000 8

2 to 3 4 16 8000 0.8 40000 4

3 to 4 3 12 4000 0.4 20000 2

4 to 5 2.5 10 2000 0.2 10000 1

5 to 6 2 8 1000 0.1 5000 0.5

6+ 1.5 6 500 0.05 2500 0.25

(*) refers to a percentage of the total oil volume with the gas measured at

standard pressure and temperature, while (**) refers to volume basis. [6]

2.10.2. Separated water

The quality of the separated water that is discharged from a separator depends

on its configuration and operating parameters. Table 2.3 below indicates that

within any range given, the effluent water will still contain some oil.

Table 2.3: Estimated Quality of Separated Water. Taken from-[9] .

WATER RETENTION

TIME (MINUTES)

ESTIMATED RANGE OF OIL CONTENT OF EFFLUENT WATER

Minimum(ppm) (%)* Maximum(ppm) (%)*

1 to 2 4000 0.4 20000 2

2 to 3 2000 0.2 10000 1

3 to 4 1000 0.1 5000 0.5

4 to 5 500 0.05 2500 0.25

5 to 6 200 0.02 1000 0.1

6+ 40 0.004 200 0.02

(*) refers to volume basis

2.10.3. Gas

The handling of a laser particle spectrometer with enough skills and experience

can be used under normal field condition to determine the volume of oil in the



separated gas. Table 2.4 below shows an approximate amount of oil content in

separated gas which has generally been accepted in recent years

Table 1.4: Estimated Quality of Separated Gas. Taken from-[9] .

OPERATING PRESSURE (PSIG)

OPERATING TEMPERATU

RE(OF)

ESTIMATED OIL CONTENT OF EFFLUENT GAS

Minimum Maximum

(ppm) (gal/MMscf)

(ppm)

(gal/MMscf)

0 to 3000 60 to 130 0.01335

0.10* 0.1335

1.00**

2.11. Measurement of Effluent Fluid Quality

The quality of the separated fluid can be measured with the aid of the following

state of art instruments as shown in table 2.5 below.

Table 2.5: Measurement of effluent fluid -[9] .

STATE OF ART INSTRUMENT MEASUREMENT

Oil in effluent water Solvent extraction/infrared absorbance

Oil in effluent water Ultraviolet absorption unit

Water in effluent oil BS&W monitor (capacitance

measurement unit)

Gas in effluent-oil Nucleonic Densitometer

Oil in effluent gas Laser liquid particle spectrometer



CHAPTER THREE

OIL-GAS SEPARATION THEORY

3.1. Factors that Influences the Efficiency of a Separation Process

3.1.1. Particle size

The diameter of particles is an important factor that should be put into

consideration when designing a separator, as it greatly affects the efficiency of

a separation process. Without the effect of turbulence, separation of small

droplet will be possible provided the liquid handling capacity has not gotten to

its maximum.-[2, 5].

When some degree of agitation is introduced into the system, the separation of

smaller particles becomes very difficult which results in the decline of the

separator performance. It is also a general believe that when the diameter of

liquid droplet in a gas phase is greater than 10µm, the separation process is

termed ineffective-[2, 5].

3.1.2. Gas velocities

An increase in the gas velocities helps to increase the amount of liquid particles

that gets to the mist extractor, thereby avoiding any form of re- entrainment.

When the handling capacity of the mist extractor is exceeded, it begins to flood

which might result into liquid carry over-[5].

3.1.3. Gas and liquid density

At constant temperature and pressure, the liquid and gas density varies with the

capacity of a separator as shown in equation 3.1 below

𝑆𝐶 = 𝜌𝐿− 𝜌𝑔

𝜌𝑔⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛3.1

3.1.4. Operating pressure

An increment in the operating pressure allows more condensation of

hydrocarbons which helps in capturing more of the liquid phase. It however gets

to a stage where an increase in pressure decreases rather than increase the

amount of liquid recovered. This occurrence is called the retrograde

phenomena-[2, 5, 14].



3.1.5. Operating temperature

An increase in temperature allows the vaporisation of gas thereby reducing the

recovery rate of the liquid phase. This leads to a decline in the capacity of the

separator-[2, 5, 14].

3.1.6. Surface Tension

The diameter of a particle varies inversely to its surface tension. This attributes

determines the amount and size of liquid particles that will be present in the gas

phase. It also affects re- entrainment as a decrease in surface tension allows

the breaking away of smaller droplets from the collecting surface-[5].

3.1.7. Number of stages

Based on previous study, it has been proved that the more stages added to a

separation train, the higher the efficiency of the separation process. However

this law only applies to a range of 2-3 stages. Above this value, there is a

decline in the efficiency of the separator making it no longer economically

attractive-[2].

3.1.8. Stain /handkerchief test

Albeit this is an archaic approach, till date it has still proved both its accuracy

and efficiency. It simply involves holding and exposing a plain white cloth along

the path of the gas stream. If no brown stain is formed within a minute, the

performance of the separator is considered adequate-[2].

3.2. Principles Used in the Separation of Oil from Gas

3.2.1. Centrifugal force

The need for the separation of larger volumes of reservoir fluid brought about

the innovation and application of centrifugal force, which has been applied in

different industrial practices such as gas -solid, gas- liquid and liquid-liquid

separation-[18].

It appears to be a very attractive and appealing solution to the challenges faced

in the oil and gas sector because of its simple design, immovable part, low cost

of maintenance/ installation and its rapid separation time of its separator. Due to

its advantages, the industry in recent years has begun to show interest in its

application, development and most especially its modifications-[19].



This force creates a cyclonic flow of the incoming fluid at a high velocity (40-

300ft/sec), separating it from the conventional separators that operates within

the range of 80-120ft/sec-[9]. Although most centrifugal separators are vertically

oriented, a horizontal separator with a centrifugal separating element can also

carry out the same function.

3.2.1.1. Derivation of its droplet velocity

Consider a centrifuge of height h, radius R2, and inner shaft radius R1, as

illustrated in figure 3.1.The reservoir fluid enters the centrifuge at a volumetric

rate of q, while it spins at an angular speed of ω. This force throws the heavier

liquid droplets out to the centrifuge wall as illustrated in figure 3.2 below-[14].

Figure 3.1: Centrifugal Forces Acting on a Particle in a Gas Stream Taken From [14]

The residence time t for the fluid in the centrifuge is expressed as centrifugal

force/volumetric flow rate of fluid and can be derived from equation 3.2

𝑡 = 𝜋 𝑅22 − 𝑅2

1 𝑕

𝑞 ⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛 3.2

For simplicity, the liquid droplet is assumed to be spherical with a uniform

diameter of 𝑑𝑝 . The area projected by the droplet can then be derived from

equation 3.3 below.

𝐴 = 𝜋 4 𝑑2𝑝 ⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛 3.3

From figure 3.1 above, it is also observed at a radius R, a drag force acts on the

droplet. The drag force, 𝐹𝑑which is due to friction, can be derived from equation

3.4 below



𝐹𝑑 = 12 𝐶𝑑𝜌𝑔𝑉

2𝐴⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛 3.4

Solving for the droplet velocity, v can be calculated from equation 3.5 below

𝑉 =[4𝑔𝑑𝑝 𝜌𝑙 − 𝜌𝑔 ]0.5

(3𝐶𝑑𝜌𝑔)0.5⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛 3.5

3.2.2. Density difference (gravity separation)

This is the most widely used mechanism for a separation process largely due to

its simplicity and its available source of gravity. At standard operating

conditions, the density of a droplet of liquid hydrocarbon to that of natural gas is

in the ratio 400 to 1600-[5,9].

This difference allows little particles of liquid hydrocarbon to slowly settle out of

the stream of gas at low velocity, while the larger particles take a faster duration

of time. This principle does not involve inlet elements, deflector or any

impingement plate; it is obtained entirely by the density difference between the

oil and gas phase-[5, 9].

The droplet velocity for a gravity separation chamber as illustrated in figure 3.2

can be derived from equation 3.6 (Souders- Brown equation)

𝑉 = 𝐾[ (𝜌1 − 𝜌2)/𝜌𝑔]0.5 ⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛 3.6

The constant K is called the separation coefficient and depends on the plate

geometry, properties of the fluid, vapour velocity, design of separator and the

degree of separation required. [12]

Figure 3.2: Forces Acting On a Particle in a Gravity Settling Chamber. Taken from-[14] .

In the separation chamber of circular cross section, with length L and diameter

h has shown above in figure 3.2, the retention time can be calculated from

equation 3.12



𝑡 = (𝜋𝑕2𝐿)/4𝑞⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛 3.12

The velocity at which the droplet falls in the vertical direction is given as v=h/t

From equation 3.12, q can be gotten as

𝑞 = 𝜋𝑕𝐿

4 𝑉⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛 3.13

Substitute for v from equation 3.10 into equation 3.13 gives

𝑞 = (𝜋𝑕𝐿/4)[4𝑔𝑑𝑝 𝜌𝑙 − 𝜌𝑔 ]0.5

(3𝐶𝑑𝜌𝑔)0.5⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛 3.14

Hence from equation 3.14, it is seen that for more droplet to settle, both the

height and the length should be at its maximum-[14].

3.2.3. Filtering

Porous filters can also be used to drain liquid mist from the gas stream-[9]. Any

filter element used for the separation process must have the following features-

[20].

Be self- cleaning which helps to reduce down time.

Be easily detachable for general cleaning and maintenance.

Be resistance to the action of both organic liquid and water to avoid

swelling.

High structural strength and relatively low pressure drop.

Have a non- wetted surface to prevent the creeping of the liquid

through the element.

3.2.4. Coalescence

As shown in figure 3.3, this principle works on agglomerating tiny liquid droplet

into one larger droplet, which can easily be removed. It is known to transform an

inlet distribution within the range of 0.2-50µm to 500-5000µm.

Coalescence packs are made of fibers and can be in the form of Berl saddles,

Raschig rings and knotted wire mesh which tends to be very fragile. They are

therefore very prone to damages during transportation or installation-[9, 21].

The coalescence process occurs via the following step.

Movement of various liquid droplets onto the fiber surface.

Agglomeration of two liquid droplets into a larger droplet takes place.



Step 2 is repeated for various small droplets.

The droplet of larger droplet for proper handling.

Figure 3.3: Coalescing Process in the Media. Taken from-[21] .

3.2.5. Impingement

This is defined as the process of a liquid mist sticking to a surface and

amalgamating into larger molecules droplets. This occurs when a flowing

stream of gas collides against an obstruction which acts as a collecting surface.

In the anticipation of a large amount of liquid from the gas stream several

impingement surfaces will be joined together for successive separation process

as illustrated in figure 3.4 below-[9].

3.2.6. Change in flow direction

An impromptu change in the direction of the flow of a gas stream creates an

inertia force. This allows the gas to flow away from the liquid mist particle while

the liquid maintains the original flow pattern. The separated liquid will either

coalesce on the surface or flow to the liquid section below as illustrated in figure

3.4 below-[9].

3.2.7. Change in the velocity of the flow

As illustrated in figure 3.4 below, an impetuous increase or decrease in the gas

velocity has a great effect on the separation process. With a decrease in

velocity, the liquid moves forward and away from the gas, while an increase in

velocity, allows the gas to move away from the liquid. Each of the phases can

then be individually collected-[9].



Figure 3.4: The Principle Of Impingement, Change Of Direction And

Velocity. Taken from-[9] .

3.3. Principles Used in the Separation of Gas from Oil

During the processing of the reservoir fluid, the removal of non-solution gas

from crude oil is very important and largely depends on the level of the liquid

hydrocarbon being handled. The major procedures used include the following

3.3.1. Heat

This process releases gas that is hydraulically retained in the oil as illustrated in

figure 3.5 below. The most efficient way to carry out this process is to pass it

through a heated water bath, where the upward flow of the oil through the water

provides slight agitation thereby breaking the gas from the oil. It is also very

effective for the handling of foamy crude oil-[9].

Figure 3.5: Two-Step Mechanism of Separating Gas from Oil. From-[2]



3.3.2. Settling

If given adequate retention time, non-solution gas will naturally separate from

the oil. It should be noted that an increase in the depth of the oil does not bring

about an increase in the emission rate of non-solution gas, considering the fact

that stacking up may prevent the gas from emerging-[9].

3.3.3. Agitation

Temperate controlled agitations also help to remove non-solution gases that are

locked in the oil due to surface tension and viscosity. In less time, the gas

bubble coalesces and separates from the oil-[9].

3.3.4. Baffling

Degassing element/baffles are positioned at the entrance of a separator. They

are very efficient and adequate for handling foamy oil. They also minimises

turbulence, separates gas from oil and eradicates high velocity impingement of

the fluid-[9].

3.3.5. Chemicals

These are chemicals that reduce the surface tension within the fluid. This

results to freeing of the non-solution gas from the oil, reducing the foaming

tendency of the oil, and increasing the efficiency of the separator. The

application of silicone upstream of the separator can be very effective-[9].

3.4. Improvements on the Gas-Liquid Separation Technology

As stated earlier, the separation technology has long been based on the vessel

type separator which is usually bulky, heavy and very costly. Based on this a lot

of research, improvement and development has been made over the last

several years in trying to look for better alternatives. Such alternatives include

the use of compact, in-line and the pipeline separation technology which are

briefly explained below.

3.4.1. Gas liquid cylindrical cyclone (GLCC)

The GLCC can simply be defined as a piece of pipe positioned vertically with a

tangential inlet inclined downward. It has the features of two outlets fixed at the

top and bottom with no moving parts or internal device as shown in figure 3.6

below-[22, 23]. It is popularly known for its boundless benefits such as being

simple, compact, and most especially its low cost of maintenance-[6].



Figure 3.6: Gas-liquid cylindrical cyclone configuration taken from-[23] .

3.4.1.1. Applications

Based on previous studies-[22], it has been proven that they can be utilised in

the following areas:

In the control of GLR for a multiphase flow meters.

De- sanders.

Well test metering.

Gas scrubbing.

Pre- separation process carried out at the upstream of a slug catcher.

3.4.1.2. Mode of operation

The well fluid enters the separator at a high velocity through the adjustable

tangential slot, creating a whirling effect of the stream around the inlet chamber.

The heavier phase which is the oil is propelled outwards against the wall of the

vortex and allowed to run through the baffle plate, while the gas converges at

the inner portion of the vortex. The vortex finder stabilises the cyclone cone

thereby providing a long path for the well fluid. This also aids the separation of

the entrained liquid from the spinning gas-[9].

This liquid is sucked through a gap in the tube wall made possible by the low

pressure area along the axis of the vortex. It is thrown out of the wall and moves

into the liquid chamber which contains baffles for the settlement of the liquid or

the isolation of the level control float. The gas vent B stabilises the pressure

within the system while the separated oil and water is drawn from nozzle C and

D respectively as shown in fig 3.7 below-[9]



Figure 3.7: Vertical Three Phase Separator Acting On Centrifugal Force.

Taken from-[9] .

3.4.2. Diverging vortex separators:

This type of separators also uses centrifugal force to carry out its separation

process. As illustrated in figure 3.8 below, the oil saturated gas tangentially

enters the vessel through the bottom. At the top of the vortex section, the

separated oil exhibits the Coanda effect which makes it moves down to the

bottom of the vessel, while the gas continuously moves spirally upward to the

gas outlet, helping to minimise the oil to gas relative velocity-[9].

Figure 3.8: Diverging Vortex Separator. Taken from-[9] .



3.4.2.1. Features

A diverging vortex separator has the following features-[9]:

It has no moving part and does not involve a change in the direction of

the gas flow

Its pressure losses are minimal

Its performance ranges from 99% to 99.9 +%.

3.4.3. Gas scrubbers

A centrifugal gas scrubber as shown in figure 3.9 is frequently used in places

where the gas has previously been separated, cleaned, transported and

processed with other equipment’s. It involves two stages of separation. In the

first stage both the free and entrained liquid are spun out of the gas by

centrifugal force, while in the second stage, gently increased centrifugal force is

used to remove the remaining entrained liquid-[9].

They are frequently found downstream of dehydrators and sweeteners to

conserve processing fluid. Also positioned upstream of gas

distribution/transmission system to remove the lubricating oil from the line. They

also help to remove all forms of impurities and materials that are detriment to

the working condition of equipment-[9].

Figure 3.9: Centrifugal Gas Scrubber. Taken from-[9] .



3.5. Subsea Separation

Subsea separation can be described as a reliable and developing technology

that is currently being utilised in the offshore sector of the oil industry. It is

generally known to improve both the recovery rate and the economics of a

subsea field over their entire life cycle-[24, 25].

3.5.1. Factors considered during the designing stage

Based on the research carried out by- [24], the following factors should be put

into consideration during the designing stage of a subsea separation unit. It

should be constructed such that;

It is both cost effective and affordable in respect to its first installation and

any modification that will be carried out in later years.

It can produce clean source of water at its outlet, as this prevent

damages to the downstream system, the formation itself and the whole

equipment at large.

It can easily separate water from its multiphase mixture as the presence

of water occupies useful space and also increases the rate of corrosion

in the vessel.

There is provision for the proper handling and disposal of the produced

sand, as agglomeration of sand can lead to blockage of the vessel. It not

taken care of immediately can eventually lead to the damage of the

entire unit.

This led to the introduction of a subsea water separation plant with an

integrated solid handling system as shown in figure 3.10 below

Figure 3.10: Subsea Water Separation Plant with an Integrated Solid

Handling System. Taken from-[24] .



3.5.2. Features of a subsea separator

The following listed below are the major feature of a subsea separator-[24].

Simple, condensed and requires little maintenance.

Very flexible with few internal components.

In case of unseen circumstances, it is easily retrievable and replaceable.

Its oil-water-sand separation system is based on the principle of

gravitational settling. This is simple to operate and also meet the

standard required for most applications.

Its distribution baffle helps to avoid blockage in the flow line.

A special inlet cyclone positioned outside the vessel, facilitates effective

utilisation of the vessel and also reduces the vessel size of the separator.

A proper design of its outlet to ensures effective separation of the

incoming sand.

Sand handling system that ensures effective disposal of sand and solids

generally.

3.5.3. Advantages of subsea separation

The following are the attractive and appealing benefits of a subsea separation

unit.

3.5.3.1. Enhanced flow assurance

The separation of water from the steam will reduce the rate of formation of

corrosion, scales, slugs and hydrate. Although the formation of wax and

asphaltenes cannot be totally stopped they can be properly managed and

handled. It can also lead to an improvement in the condition of the pipeline as

transportation becomes stable-[24].

3.5.3.2. Improved production rate/ reservoir recovery

This benefit is the major aim of setting up a subsea separation unit. This is

achieved by reducing the back pressure, increasing the water injection capacity

which enhances both start-up and shut-down conditions. Its measure of

improvement varies within the range of 10-25% and 5-10% for the oil production

rate and the reservoir recovery rate respectively-[24].

3.5.3.3. Reduced environmental impact

Due to the reduction in the amount of chemicals being applied to prevent the

formation of corrosion, hydrate etc. pollution is greatly reduced-[24].



3.5.3.4. Improved safety condition for personnel

The unit is remotely operated and therefore requires no human assistance.

This eliminates the exposure of personnel to hazardous environment-[24].

3.5.3.5. Reduction in the operating expenditure

The technology does not involve any construction of platform or floaters

therefore eliminating the total cost of topside water separation, treatment and

injection system. Also the ability to be able to re-use existing facilities for new

field also helps in reducing capital expenditure-[24].

3.5.3.6. Greater utilisation of the flow line

The removal of water in the system reduces the space constrain in the flow line

thereby giving room for more production-[24].

3.5.4. Potential drawbacks of subsea separation

3.5.4.1. Associated cost

From previous research, it is estimated that the overall CAPEX and OPEX of a

45000bpd subsea separation unit in a water depth of 1500metre is

approximately US$ 10-12 million and US$ 2-3 million per year respectively-

[26].

3.5.4.2. Reliability

The separation unit cannot be termed as being reliable, as the reliability of the

whole system depends on the efficiency of the sub-systems or processing

facilities-[26].

3.6. The Subsea Separation Concept

The subsea separation process is very similar to that of the conventional

process since they both operate on the principle of gravity. Its unique feature

that makes it stand out is the introduction of a gas bypass line. The well fluid

enters the separator tank through the semi –cyclone inlet which ensures that

small droplets of liquid are not been formed when there is a reduction in

momentum of the mixture.

Through the gas bypass line the gas flows to the outside of the vessel thereby

minimising the size of the vessel, while the remaining bulk of fluid is separated

inside the tank through the principle of gravity settling. With the aid of the water



injection pump, the water is re- injected back into the formation, while the oil

and gas are recombined before they flow to the downstream pipe-[24]. The

effectiveness of this approach can easily be noticed in table 3.1below where a

great reduction in the volume and weight of the vessel are easily observed.

Table 3.1: Separator Vessels Dimensions for Different Separator Concept.

Taken from [25]

Separator

concept/ Inlet type

Length/Inner diameter

Vessel Volume Vessel weight

Convectional

inlet cyclone

design

15.0m/2.60m 100% 100%

Minimum vessel

size inlet device

13.5m/2.25m 67% 69%

Novel separator

concept with gas

bypass

12.m/2.00m 47% 52%

3.6.1. Disposal of the produced water

There are basically two ways by which the water produced alongside the well

fluid can be handled or disposed-[25]. They are

The water injection module can help in re-injecting the produced water

back to the reservoir. This module comprises of an electric motor,

centrifugal force, piping and instrumentation tool.

It can also be discharged directly into the sea on the condition that the

quality of the produced water has been adequately monitored.

3.6.2. The subsea sand handling system

The handling and disposal of sand has always been a major challenge during

the selection and designing stage of a subsea separation unit. This is largely

due to the fact that the process is filled with a lot of uncertainties and limitations

that needs to be verified-[27]. The uncertainties include

Uncertainty as regard to the actual rate of sand production

Imperfect tool for the detection of sand production



Not having an in-depth knowledge of the long term effect of sand

production on the processing equipment

Uncertainty regarding the place where the sand will be kept after it’s

processed in a subsea station.

Uncertainty regarding how the sand will be transported.

3.7. Application of Subsea Separation System

3.7.1. Case 1: Tordis subsea separation boosting and injection system

The Tordis field is located in the Tampen area of the Norwegian North Sea. It

began production fully in the year 1994 while the installation of the subsea

separation boosting and injection (SSBI) system was established in 2007. It is

positioned between the existing subsea field and the Gullfaks C platform as

shown in figure 3.11 below-[27].

The SSBI is a 17m long semi- compact vessel having a diameter of 2.1 meters,

a retention time of 3 minutes with a design capacity of 100,000 bwpd and

50,000 bopd. The major aim for the installation is to increase the Tordis field

recovery factor from 49 to 55%.

Figure 3.11: Tordis Subsea Separation System Connected To Gullfaks C

Platform, Courtesy “FMC Technologies”

It is known to be the world first full scale seabed facility comprising of a

separator that removes water from the well stream, a multiphase pump that

helps in raising the production rate and a water injection pump that re- injects

the water back to the reservoir as shown in figure 3.12 below-[28] .



Figure 3.12: Process Overview of the Tordis SSBI. Taken from-[28] .

3.7.1.1. Operational procedure

It follows the same process as explained in section 3.6.

3.7.1.2. Sand removal system

The handling of solid was done in a step- wise process-[27] as listed below.

The sand enters the separator inlet with the other component of the well

stream

Through the principle of gravity, the sand is being separated to the

bottom of the separator vessel.

The sand is removed from the bottom by any sand removal system

The sand is then transported to a gravity desander vessel where it

accumulates.

The water from the water injection pump pressurises the de-sander

vessel which aid the removal of the sand.

3.7.2. Case 2: The Troll C pilot separation system.

The troll field is located at the west of Bergen, off coast western Norway. It is

presently known to be one of the largest developments of the subsea

technology with 107 wells presently in operation-[29].

The Troll C pilot separation unit as shown in figure 3.13 was built and designed

by ABB Vetco Gray presently known as General Electric Company. The unit

was designed from carbon steel with an inner coating of Inconel 625 to prevent

the formation of corrosion. It was installed in a water depth of 340m at a step –



out distance of 3.5km from the Troll C platform and 120m from the subsea

template-[29].

In total the unit measures 17× 17×8 metres in size, weighs 350 tons in air and

has both liquid rate and water injection pump capacity of 60,000 bbl/D and

40,000bbl/D respectively-[30].

Figure 3.13: Troll C Pilot Separation Plant .Taken from [29]

3.7.2.1. The objectives of the separation unit

The separator unit was designed to carry out the following features-[31].

To separate bulk amount of water from the well stream with the aid of a

cyclonic inlet device and re- injects it back to the aquifer of the same

formation.

To maximise the production output by improving the water treatment

capacity of the platform.

To authenticate the practicability of the technology.

Its mode of operation is similar to that of the Tordis SSBI but different in the

approach used for the disposal of sand.

3.7.2.2. Disposal of sand

The disposal of the produced sand is done through via a sand removal system

as shown in figure 3.14 below. It consists of a group of pipes positioned at the

bottom of the separator which aids the flushing out of the sand while another set

of pipes helps to absorb the particles that contain water. The flushing unit is

designed in such a way that the filters and other accessories can trap the sand

particles in such a way that they are recovered at the surface-[31].



Figure 3.14: Troll C Sand Removal System. Taken from-[31] .

3.8. Inline Separation Technology

Inline separation technology can be described as a recent and developing

separation technology currently used in the oil industry. It uses very high

gravitational force to carry out its separation process-[27] in the following area:

Gas- liquid separation

Liquid- liquid separation

Separation of solid from the well stream.

3.8.1. Advantages of Inline separation technology

The following include the advantages of an inline separation technology-[32, 33]

When compared to conventional separators, there is an immense

reduction in both size and weight.

It does not require any assistance of personnel’s and does not consume

power, which leads to a reduction in the operating cost.

It is very simple to operate and require little maintenance.

It can easily be merged with existing technology.

It can be tailored to suit any situation.

It is known to improve the effectiveness of a separation process, since

it’s not prone to fouling.

It is very flexible with no moving part

It reduces the amount of gas being flared into the atmosphere.

3.8.2. Inline gas – liquid separation

This is the most matured inline technology that was first put into operation in

the year 2003-[32]. A complete inline gas- liquid separation unit comprises of

the following;



3.8.2.1. Gas Unie TM

This carries out separation of large amount of liquid or gas. It also helps to

protect equipment like compressor or gas turbine etc.-[33].

Figure 3.15: Gas Unie TM . Taken from-[33].

3.8.2.2. Inline Phase splitter

This allows bulky separation of mixed flow into their individual phases.

Depending on the operational condition, it is possible for a phase to be 99%

pure, while the other phase can have carryover within the range of 5-10%. The

individual phases are then taken to either a De liquidiser or Degasser for further

treatment-[33].

Figure 3.16: Overview of the Main Features of the Inline Phase

Splitter Gas- Liquid Separation Technology. Taken from-[32] .

3.8.2.3. In line Degasser

As shown in figure 3.17 below, an inline degasser basically consists of two

sections namely: a cyclonic pipe section that separates the gas from a liquid



flowing stream and a gas scrubber that further helps to clean the separated

gas-[33].

3.8.2.3.1. Mode of operation

The predominantly liquid stream passes through a low pressure drop mixing

element, which allows bubbles to be formed in the liquid so has to avoid

stratified flow from occurring. The stationary swirl element which is positioned

downstream to the mixer introduces a rotational force into the stream.

This force together with the large variation in density between the gas and the

liquid allows the gas to drift to the centre of the cyclone while the liquid forms a

spinning membrane on the exterior side of the pipe wall. Through the spherical

section in the cyclone, the gas moves to a vertical scrubber positioned on the

top section of the degasser where the entrained liquids that are still found in the

gas phase are removed from the system.

The rotational force is then stopped by an anti – swirl element located

downstream of the separation zone-[32].

Figure 3.17: Schematic Representation of a Degasser. Taken From-[32] .

3.8.2.4. Inline De-liquidiser

As illustrated in the figure 3.18 below, it is made of two parts namely: a cyclonic

pipe section that separates entrained gas from the liquid phase and a small

liquid boot that further cleans the liquid phase. It basically works in opposite

direction to that of a degasser-[33].

3.8.2.4.1. Mode of operation

It is essential that the mixing element be positioned at the inlet of the separator

to avoid the occurrence of stratified flow. The swirl element introduces a

rotational force into the stream; this force together with the difference in density



of the mixture creates a liquid mist on the exterior part of the pipe wall while the

gas is removed through a smaller diameter pipe attached to the main pipe.

Through the pipes, the liquid with some little amount of gas moves to a vertical

boot section, where the gas is detached and re- injected back to the centre of

the swirl element. An anti -swirl element positioned at the downstream of the

liquid boot stop the rotational force-[32].

Figure 3.18: Schematic Representation of a De-Liquidiser. From -[32].

3.8.2.5. Inline De-Mister/ Spiraflow TM

This is referred to as the final cleaning stage of the gas. As illustrated in figure

3.19, it is made up of a group of small diameter cyclones that removes tiny

liquid droplet that still retained in the gas stream. Its mode of operation is similar

to that of convectional scrubber but works more in a condensed way. They are

sometimes added as internals to a gas scrubber-[4, 33].

Figure 3.19: Inline Demister Spiraflow. Taken from-[33] .

Table 3.2 below shows the characteristics of the different sections of an inline

Gas/Liquid separation unit.



Table 3.2: Characteristics of Gas/Liquid Separation Equipment. From- [33]

GasUnie TM

Degasser De-liquidizer

Phase Splitter Demister Spiraflow

Separation Efficiency

90-99% removal of incoming

gas


gas


gas

About 98%* 99% removal of incoming

gas

Continuous Phase

Gas or Liquid

liquid Gas Gas or Liquid Gas

Dispersed Phase

GVF**<10% GVF**<60% LVF***<60% 20&<GVF<95% Gas

Second stage

separation

NA Scrubber Liquid boot NA Marsh Pad

Control system

required

YES YES YES N0**** N0

Control Strategy

Liquid level in GasUnie

Liquid level in scrubber

Liquid level in boot

Application dependent

_

Turndown Ratio

50% 50% 50% 50% 50%

Pressure drop

0.2 to 1 bar depending

on the operating pressure

0.45 to 2.5bar

depending on the

operating pressure

0.4 to 0.7bar

depending on the

operating pressure

0.4 to 0.7bar depending on the operating

pressure

0.2 to 0.7bar

depending on the

operating pressure

Slug handling capacity

High Moderate Moderate Low High

Fouling High Low Low Low High

* Depends on operation strategy, ** GVF Gas volume fraction, *** LVF

Liquid volume fraction, **** depends on customer requirements, if

performance is required, control system must be included.

3.8.2.6. Application of Inline gas – liquid separation technology

This technology has been successfully applied in the following areas-[4]:

The Inline Degasser was used in Al-Huwaisah oil field of North Oman

owned by Shell. It was merged with an existing compact vessel

technology for re- injection of water.

The Inline De liquidizer was applied in the eastern through area project

(ETAP) owned by BP to improve both the scrubbing efficiency and the

glycol based dehydration process.



Figure 3.20: Inline De-liquidiser BP-ETAP. Taken from-[4] .

The Inline phase Splitter was used in Statoil Veslefrikk to reduce the

pressure drop between the well head platform and the processing

platform, which increases production-[4].

3.8.3. Inline liquid -liquid separation

This is installed majorly to achieve high separation efficiency for high inlet water

cut, especially for mature fields. It performs its separation process-[4] via the

following way

Merging its own technology with an existing one

Removing a large quantity of water upstream the existing separator

Water polishing of the oily water downstream the existing gravity

separator.

Figure 3.21: Key Advantage of Inline Liquid- Liquid Separation. Taken

from-[4] .

The inline De-water has been tested at Statoil High Pressure test loop in

Porsgrunn-[4].

3.8.4. Inline sand separation

The inline De-sander when compared to the conventional type has the unique

features of being simple, strong, contains no moving part and involves no power

consumption [4].



3.8.4.1. The basic operational principle

The axial swirl elements produces a very high rotational velocities which when

combine with the gravitational force in the separation chamber pushes the solid

outward and then flows downward to the solid reject where they can be

extracted as accumulated particles or condensed slurry-[4].

Figure 3.22: Inline sand separation unit taken from-[27] .

This technology has been used at the Statoil Heidrum field in North Sea at

2007, where it was tagged being satisfactory.

3.9. Pipe separation

This is a developing technology that is currently used in deep and highly

pressured subsea area. The separation process also adopts the principle of

gravity, but it is carried out in a small diameter pipe as against the big

convectional vessels. This results in a reduction in weight and cost-[27].

Figure 3.23: Pipe Separation Concept, Using Pipe Segment Instead Of

Vessel. Taken from [27]



CHAPTER FOUR

SOLID SEPARATION, DISPOSAL AND HANDLING SYSTEM

4.1. Background Study

The production of solids alongside the reservoir fluid is a phenomenon that

occurs during the drilling stage of every well. These solids are inorganic

insoluble particles or semi- soluble deformable particles that either comes from

a natural or artificial source-[34].

Currently, research has it that roughly 90% of the world oil and gas well are

being discovered in sandstone reservoir, among which 25-30% of the well

experience sand production at a stage in their well life, with concentrations

varying within the range of 5-250ppm-[35]. This result in a decline of the overall

rate of production; leading to the discovery and implementation of a solid

separation, disposal and handling system.

4.2. Sources of Solids

There are basically two sources where produced solids can originate from. This

includes the natural and artificial source.

4.2.1. Natural Source

They arise naturally from the reservoir material and appear in the form of sand

or clay. Sand particles are described as the detrital grains of Si02 oxide, while

clay is the detrital grains of hydrous aluminium silicates-[34]. Table 4.1 below

shows the physical properties of natural solids.

Table 4.1: Physical Properties of Natural Solids .Taken from- [34]

Property Sand Clay

Specific Gravity 2.5-2.9 2.6-2.8

Shape Factor 0.2-0.5 0.1-0.3

Size Range(µm) 50-1000 5-30

Conc. (ppmv) 5-100 <1

4.2.2. Artificial source

These include solids that are being introduced into the well stream as a result of

the addition of foreign bodies-[34].Table 4.2 below shows the physical

properties of artificial solids.



Table 4.2: Physical Properties of Artificial Solids. Taken From - [34].

Property Fracture sand Corrosion

Products

Gravel Pack

Specific Gravity 2.6-3.6 5.5-6.0 2.6-3.0

Shape Factor 0.5-0.9 0.1-0.5 0.5-0.9

Size Range(µm) 150-2000 10-10000 250-3500

Conc. (ppmv) 0-10000 <2 0(unless failure)

4.3. The Effects of Produced Sand

The effect of sand production on the equipment’s, formation and the

environment as a whole-[16, 34] include the following:

It leads to the intense corrosion of both pipe works and valves even at a

low flow rate.

If left to accumulate in the separators for a long period of time, activates

the presence of bacteria and hydrogen sulphide. This aids the formation

of corrosion.

It leads to a decline in the retention time thereby minimising the efficiency

of the separation process.

It can lead to damages in formation during the process of re-injection.

It results to the regular shutdown of the plant during the separation

process.

4.4. Techniques Used in the Disposal of Sand

There are basically three methodologies-[34] that are currently being adopted in

the separation and disposal of solid, they include

Production boundary to regulate the amount of sand inflow

Convectional exclusion methodology

Inclusion methodology.

4.4.1. Production limits

This method adopts the conservative approach of ―Zero Sand Production‖. It

operates on the principle of drilling well in areas where there is zero amounts

sand production. It does this with the aid of a reservoir pressure versus bottom

hole pressure map.



Although it reduces the overall capital expenditure, it has its limitations of

reducing the rate of production, continuous redefining of the boundaries of the

map when variations occurs in the well profile-[34].

4.4.2. Convectional exclusion methodology

This approach combines various techniques with the main aim of preventing the

solids from entering the wellbore. They include the use of mechanical retention

principle (screen or slotted liner), gravel packs, chemical consolidation etc.

The main advantage of using this approach is that it protects the production

tabulars, wellhead chokes, flow lines and facilities equipment from damage. It

however allows the accumulation of solids near the well bore, which eventually

results in a decline in the production rate-[34].

4.4.2.1. Downhole equipment

This is the most common and demanding technique used for sand control in

order to enhance the production of hydrocarbon. It incorporates the principle of

mechanical retention by the use of screen or slotted liners which restrict the

entrance of the solids into the well fluid. A screen is often used with the addition

of gravel packing positioned around the external surface of the screen of the

separator-[34].

4.4.2.2. Wire wrap screens

As illustrated in figure 4.1, they are keystone shaped wrap wire screens

designed majorly for the separation of coarse well sorted sands. They ensured

that the gravel placed between the screen and the formations are maintained

while trying to minimize any production constraint. It has the following

advantages over the others.

4.4.2.2.1. Extra strength

It’s all welded screen provides a combination of high strength and a higher

corrosion resistance. Its stainless steel wire is also designed in such a way that

it remains still in times of unlikely occurrence.

4.4.2.2.2. Large Inlet area

Its screen also provides a large inlet area which prevents the blockage of flow,

lowers the entrance velocity for produced fluid and also eliminates the tendency

of screen erosion.



4.4.2.2.3. Filtration assurance

It is equipped with the exact gauge control and gauge spacing which

guarantees greater reliability.

4.4.2.2.4. Filter Construction

Its keystone shape wrap wire forms a v shaped opening between the wraps

which allows a self-cleaning action that remarkably reduces flow friction.

Figure 4.1: Wire Wrapped Screen Courtesy “Halliburton”

4.4.2.3. Expandable Sand Screen

This is presently considered to be the strongest in the industry with collapse

strength of 2500psi. It comprises of three layers namely: A slotted base pipe

structure, the filter media and an outer protection /encapsulating layer-[36, 37].

Figure 4.2: Expandable Sand Screen Construction. Taken from-[37].

The filter media which is an expandable sand screen is a woven metal wire

media that is attached to the slotted base structure to ensure that the sand

integrity is maintained. The outer protection house serves has a protection

covering for the filter media.



4.4.2.4. Metal mesh screen

This was first adopted in the 1980 and comprises of a base pipe, layered

filtration jacket, an outer shroud, a perforated base plate and several spacer

rings. It has the advantage of having a lesser chance of being damage during

installation stage with a high corrosion resistance-[38, 39].

Figure 4.3: Photographs of the Various Components Used For Testing a

Metal Mesh Screen Assembly. Taken from-[39] .

4.4.2.5. Gravel packs

This is referred to as the most widely used sand control technique in the oil

industry. It consists of a perforated liner placed in the well, enclosed by a mass

of gravel. This gravel acts as a depth filter which prevents the sand from

entering the wellbore-[40].

Figure 4.4: Openhole Gravel Pack Courtesy “Sclumberger”

4.4.2.6. Chemical consolidation

This involves the sealing of sand grains several feet down by the use of

environmentally accepted chemicals. The major aim is to raise the residual

strength of the formation thereby intensifying the sand maximum free rate. E.g.

the application of organo-silane - [34, 41].



4.4.3. Inclusion methodology

This is the most common method adopted for the separation and disposal of

solid. It involves the process of injecting a working fluid into the wellbore which

helps to circulate, lift and carry the solid particle to the surface for proper

separation and disposal. The separation of the solid is then carried out via a

multiphase de-sander prior to the separator vessel-[34, 35].

4.4.3.1. Advantages

It reduces the tendency for skin damages due to the free flow of the sand

alongside the well fluid-[34].

4.4.3.2. Disadvantages

It eventually leads to the damage of the formation due to its contact with

the working fluid.

In low pressure well, there is a large tendency for the working fluid to

leak into the formation. This leads to additional time needed to return the

well back to its normal operational mode.

It can lead to the erosion of tabulars, choke, and flow lines which

ultimately results in flooding of the production separator

The working fluid might be in the form of energised fluid or foam. If not

properly handled can lead to complications during the separation

process. [34,35]

4.5. Integrated Sand Cleanout System

4.5.1. Structure and principle

The system consists of two major subsystems namely: The surface subsystem

and the underground subsystem. As shown in the figure 4.5 below the surface

subsystem comprises of a multistage centrifugal pump, a separation tank and a

sand storage tank-[35]. A complete underground system has a jet pump, a

packer, a flow diverter, a sand cleanout pipe and a jetting nozzle as illustrated in

figure 4.6 below

4.5.2. Mode of Operation

The water which is the working fluid is boosted by the multistage centrifugal

pump and then inserted into the wellbore through the annulus. The flow diverter

as shown in figure 4.6 below separates this fluid into two parts. While one part



acts as the sand carrier fluid, the other part acts as the power fluid of the jet

pump-[35].

Figure 4.5: Schematic of the Surface Subsystem. Taken From-[35] .

The sand carrier fluid flows downward through the sand cleanout pipe and the

jetting nozzle which is located at the bottom of the cleanout pipe. The jetting

nozzle coverts the high pressure into a high velocity head. The high velocity

helps to lift the sand particle from the bottom of the wellbore to the throat of the

jet pump-[35].

The power fluid of the jet pump produces a high velocity which helps in lowering

the pressure at the bottom hole. This aids the absorbing of the carrier fluid

alongside the sand particles into the fluid-[35].

Figure 4.6: Schematic of the Underground Subsystem. Taken From-[35] .



4.5.3. Sand transportation behaviour

For an effective sand cleanout operation, it is essential that the settled sand

particles at the bottom of the separator are lifted upward to the surface.

Therefore the critical velocity of the fluid below which the solid will form a bed at

the wellbore must be known-[35].

4.5.3.1. Static sand settling test

A sand particle is assumed to have an ideal spherical shape that settles in an

immovable Newtonian fluid. There is no incorporation of static electricity,

external centrifugal force or collision within the system.

The free ultimate sand settling velocity can then be calculated from the equation

below-[35].

us0 = 4gds ρs − ρl

3CDρ1⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛4.1

Where g is the acceleration due to gravity, m/s2; 𝑑𝑠 is the diameter of the

spherical sand particle, m; 𝜌𝑠 and 𝜌𝑙 are the densities of the sand particle and

the working fluid, respectively, kg/m3; and 𝐶𝐷 is the coefficient of resistance,

which is a function of the Reynolds number of the sand particles.

4.5.4. Effect of sand interference settling

There is a great tendency for variation in the ultimate sand settling velocities

due to the interference between the sand particles and its surrounding medium.

Experiments carried out shows that if the interference effect has to be taken into

consideration, then the ultimate sand settling velocity with interference can be

derived from the equation 4.9 below-[35].

𝑢′𝑠0 = 𝑢𝑠0 1 − 6.55𝐶𝑆 ⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛4.9

Cs is believed to be the volumetric percentage of the sand, within a range of from

0-0.05.

4.5.5. Effect of sand particle shape

For sand particles that do not have the ideal spherical shape, a sand factor is

then considered to measure the effect that the sand particle shape has on the

ultimate sand settling velocity.



The shape factor is the ratio of the true ultimate sand settling velocity to the

ultimate settling velocity of an equivalent sphere. The ultimate settling velocity

can then be derived from the equation 4.10 below-[35].

𝑢𝑠𝑜𝑠 = 𝛼𝑢′𝑠0 ⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛 4.10

Where α is the shape factor of the formation sand particles.

4.6. De-sander (solid liquid hydro cyclone)

De-sanders are solid control equipment’s that separates produced sand from

the well fluid-[16].When compared to the other alternatives, it is proven to be a

better and more effective technology-[16] due to its following benefits:

Its ability to remove sand without necessarily shutting down the system,

lesser weight , capital effective, requires little or no man power

Requires little cost for maintenance and operation.

4.6.1. Types of de-sander

There are basically two types of de-sander namely: the vessel and the liner

type.

4.6.1.1. The vessel style

Its vessel acts as the de-sander itself, having nominal diameter within the range

of 3-30 inch. They are applied in areas where large flow rate are observed with

a combination of coarse separation size. They are very cost effective compared

to the liner type-[16].

Figure 4.7: Schematic of the Vessel Style De-sander courtesy “Process Group”

4.6.1.2. The liner style

They are designed to have multiple liners, where the individual liners have a

nominal diameter within the range of 0.5-4 inch. They are used for any type of



flow rate in combination with fine separation size. It has more capacity which

gives it an edge over the vessel style in the oil and gas industry-[16].

Figure 4.8: Liner Style De-sander Courtesy “GFI Process Controls”

4.6.2. Selections and applications of de-sanders

Table below illustrates the various criteria by which a de-sander can be selected

Table 4.3: De-sander Selection Criteria. Taken from-[16].

Criteria Vessel style Linear Style

Inlet Solid

concentration>1 vol%

Yes No

Large solids(>5mm) Yes No

Fine particle

recovery(<25µm)

No Yes

(>900lbm) ANSI design No Yes

Vessel fabricated of any

metal

Yes Yes

Linear available in

ceramic

No Yes

Pressure vessel

subjected to wear

Yes No

Replaceable wear

components

Yes Yes

http://www.gfiprocess.com/partner-id.asp?id=17



4.6.3. Components of a de-sander

All solid liquid hydro cyclones comprises of four major components namely: the

Inlet, overview, cone and tailpipe

4.6.3.1. Inlet section

The main component is the cylindrical feed chamber, which helps to regulate

the degree of turbulence that comes with the incoming flow. It should also be

noted that the smaller the inlet size, the greater the tangential velocity at the

hydro cyclone inlet, resulting to a more effective separation process-[42].

4.6.3.2. Overview

This section consists of the Vortex finder also called the Core stabilizing shield

(CSS). This is a cylindrical shield that surrounds the fluid core and provides the

following benefits-[42], as listed below:

It protects the core from any potential turbulence

It decreases the available cross sectional area which boosts the

tangential velocity. This helps in enhancing the separation process.

4.6.3.3. Cone

Although they vary in different angles and geometrics, they basically perform

the same function. They increase the amount of centrifugal force that is needed

for the separation process as the fluid flows through the cone narrowed cross

sectional area-[42].

4.6.3.4. Tailpipe

This improves the retention time required for a separation process. Based on

experiment, it is observed that the smaller the diameter of the tail pipe, the

greater the tangential velocities-[42].

4.6.4. Mode of operation of a de-sander

It works by directing inflow tangentially near the top of the vertical cylinder. This

spins the entire contents of the cylinder, creating centrifugal force in the liquid.

Heavy components move outward toward the wall of the cylinder where they

agglomerate and spiral down the wall to the outlet at the bottom of the vessel.

Light components move toward the axis of the hydro cyclone where they move

up toward the outlet at the top of the vessel.



4.7. Description of a Surface Facilities Sand Handling System

Figure 4.10 below is a decision diagram showing the outline of solids – handling

system taken from-[16].It is basically sectioned into five areas namely:

Separation, Collection, Cleaning, Dewatering and Haul-aging.

4.7.1. Separation

The solid is separated from other process fluid, through the use of a de-sander,

filters, gravity vessel, sand trap or sand jets. Fortuitously the process equipment

can also carry out this task [16, 34].

4.7.2. Collection

The separated solid phase is being combined together at a central place via a

de-sander accumulation vessel or a designed sump tank. An enclosed

collection method should be used when chemicals or radioactive materials are

involved-[16, 34].

4.7.3. Cleaning

This stage is usually carried out before any handling process, and it involves the

removal of any hydrocarbon elements or chemical contaminant. It might require

the use of chemicals or can be done via thermal treatment-[16, 34].

4.7.4. Dewatering

As shown in figure 4.9 this refers to the reduction in volume of the solid slurry,

using gravity drainage containers filter press or screw classifier. It reduces the

disposal volume by 90% producing a solid cake with less than 10% water tight-

[16, 34].

Figure 4.9: Dewatered Solids Removal. Taken from - [34].



4.7.5. Haul-aging

This is commonly known as the transportation / disposal stage. It involves the

mixing of the solid with water. The slurry can be disposed by injecting it back to

the well, through a landfill or overboard method. The design of this stage is

strictly based on the location and the disposal requirement-[16, 34].

4.8. New Generation De-sander System

This system is an update of the existing de-sander unit. It comprises of a new

generation de-sander, a solid collection vessel, a recirculation pump and an

internal header with an educator installed in the production separator-[43].

It prevents the damage of formation by eliminating any form of interruptions in

the production process. These interruptions might come in the form of solid

removal and repairs caused by sand.

4.8.1. Features

As compared to the existing de-sander, it has the following unique attributes-

[43] as listed below

Smaller footprint and a significant reduction in weight.

Lower pressure drop with zero liquid loss

Does not require much maintenance and monitoring

Constantly removes agglomerated sand that has settled at the bottom of

the vessel without the need to shut down the plant.

It can handle the issue of slugging for up to 50,000ppm

It prevents the damage in formation by eliminating any form of

interruptions in the production which might come in the form of solid

removal and repairs caused by sand.

4.8.2. Mode of operation

The new generation de-sander operates on the same principle as the existing

de-sander system but has the following modifications on its handling system.

4.8.2.1. Solids collection vessel

This can be described as a compact closed tank specially designed to handle

solids and little amount of liquids that are separated or removed from the de-



sander. As the solids are being captured for handling, the liquid is purged and

returned back to the well, thereby reducing the rate of loss of liquid.

The solids are also being purged at a constant rate into the solid retention

vessel. Each of these vessels has eight solids collection bags designed within

stainless steel baskets as shown in figure 4.11. To aid a continuous and quick

removal of sand, the vessels are detached from each other with a valve-[43].

Figure 4.11: Inside the Solids Collection Vessel. Taken from-[43] .

4.8.2.2. Internal header with educator

The introduction of an educator as shown in figure 4.12 helps to prevent the

accumulation of solid in the production separator. It provides a venturi action

which boosts the input flow rate for the sole purpose of sweeping the solid to

the de-sander where they can be separated-[43].

Figure 4.12: An Educator. Taken from-[43]

It should be noted that if the educator is not installed properly, it might result in

solid being entrained in the field which might possibly lead to emulsion-[43].



Figure 4.10: Decision Diagram Used to Decide the Outline of Solids –Handling System



CHAPTER FIVE

THE SUITABILITY OF THE DIFFERENT TYPES OF TECHNOLOGY AND

POSSIBLE SOLUTIONS TO PROBLEMS ENCOUNTERED (CASE STUDIES)

5.1. Rational Criteria for Gas/Oil/Water/Sand Separation

Based on knowledge gained during this study, the following highlights the

different criteria’s used in selecting the most suitable technology for a

separation process

The relative amount of gas and oil in the well stream

The variation in densities between the liquid and the gas phase

The variation in viscosities between the liquid and the gas phase

Operating parameters at which the separation process is to be carried

out

The level of re- entrainment i.e. the amount of liquid in the gas phase or

the amount of gas in a liquid phase

The concentration of impurities and other extraneous materials e.g.

sand, silt, scale, dust etc.

The suitability of each separation technology are listed below

5.2. The Separation of Oil from Gas

5.2.1. Vertical separator

A vertical separator is used more effectively in the following areas

Reservoir fluids having a high GLR.

Well fluid that has a significant amount of solids.

Horizontal space limitation.

Unstable liquid capacity e.g. slugging well/intermittent gas lifts well.

When there is a possibility of liquid condensation.

A necessity to have an easy means of level control.

Low flow rate of the well stream

Separation of reservoir fluid that oscillate regularly at a quick rate.

No amount of entrainment is to be tolerated.

When the GOR of the well stream are at the extreme i.e. too low or too

high.



5.2.2. Horizontal separator

A horizontal separator is best applied in the following areas

When there is a need for a thorough separation process.

Where the handling of foaming crude oil is required.

Handling of little or no amount of surge.

Vertical height limitation.

Reservoir fluid with a high-medium GOR.

Reservoir stream with a high GLR.

Well with relatively constant flow rate.

Where conservation of space is necessary by stacking multiple unit.

Three phase separation process which requires the need to construct a

bucket and weir plate.

5.2.3. Spherical oil and gas separators

Although currently, the designing of spherical separators has been stopped,

they are best applied in the following area

Well fluid with a high GOR, constant flow rate and no liquid slugging.

Vertical and horizontal space limitation.

A small separator needed for easy transportation.

5.2.4. Gas liquid cylindrical cyclone

A GLCC separation unit should be selected if the following requirements are

needed for a separation process

A separation efficiency of 99.9+%

Minimum pressure losses.

A simple and compact vessel.

Separation of large amount of solid without the termination of the oil

production process

A low cost of maintenance.

Regular testing of both the quality and quantity of the well stream.

A partial separation process

A means of regulating the GLR in a separation process.

5.2.5. Gas scrubbers

They are selected for separation processes that requires



An effective and continuous separation of liquids and solids from a gas

stream.

No room for maintenance and shutdown.

5.2.6. Subsea water separation plant with an integrated solid handling system

They are adopted in areas that requires

The need to prevent the formation of hydrate in a cold deep environment

A simple and compressed separator vessel.

A system that can easily be retrievable and replaceable.

A proper handling and disposal of the produced sand and solids.

An improved production rate.

An enhanced flow assurance.

5.2.7. Inline separation technology

An Inline separation unit should be selected if the following requirements are

needed

A high gravitational force for the separation process.

A separation process that can easily be merged with existing ones.

A technology that can be easily tailored to suit any situation.

A separation unit that is simple to operate and requires very little

technology.

5.2.8. Pipe separation technology

A pipeline separation technology should be considered in areas that requires

No separation vessel.

A great reduction in cost as compared to other technologies.

5.3. The Separation of Solid and other Extraneous Materials

5.3.1. Production limits principle

They should be used in areas

That operates on the ―Zero Sand Production‖ principle whose objective is

to form a rock from the agglomeration of sand.

Where the solid separation process aims to intensify the residual

strength of the formation, thereby raising the maximum sand free rate.



5.3.2. Conventional Exclusion Technology

5.3.2.1. Downhole equipment’s with the use of screen or slotted liners

They are most suitable in areas that requires

The solids being prevented from entering the wellbore, during the

separation process

The application of mechanical retention principle.

The protection of production tabular, wellhead chokes, and other facilities

equipment from damage during the separation process.

A sand separation process with extra strength and large inlet area (Wire-

wrap screens).

A sand separation screen with a collapse strength of 2500psi

(Expandable sand screen).

An ideal separation process for a short radius horizontal well, with a high

corrosion resistance (Metal- mesh screen).

A sand separation process that reduce the risk of plugging. (Metal mesh

screen).

5.3.2.2. Inclusion technology

They are selected for separation processes that requires

A working fluid which lifts the solids to the surface, for proper handling

and disposal.

The ability to continually dispose solids without necessarily shutting

down the whole processing unit. (Desander).

Little cost for maintenance and operation. (Desander).

5.4. Different Methodologies Adopted By Companies for the Disposal of

Sand and Problems faced.

5.4.1. Case Study One

The installation of a Sand Disposal, Separation and Handling Systems on the

Grand Isle Block 16L and West Delta 73 A-D p Production Platform.

5.4.1.1. Background story

Exxon Company faced major problems when it came to the issue of solids

handling both on the offshore platform and in pipelines. In addition to this, the

existing antipollution laws led them into carrying out some researches where



they discovered the efficiency of the use of centrifugal force for the

disposal/handling of solid impurities.

A pilot unit was set up and tested based on this principle incorporating a lot of

modifications. This led to the design of a more reliable, less complicated system

which was first installed on the Grand Isle Block 16L platform and the West

Delta 73 A-D production platform. The pilot unit had to be tested to certify the

reliability of the equipment’s paying critical attention to the sand discharge

system and its quality-[44].

5.4.1.2. Description of the Process

5.4.1.2.1. Mode of operation for the sand handling system

Figure 5.1 below illustrates a schematic diagram of the sand handling system. It

is divided into three sections namely: sand removal, sand transporting and the

sand cleaning/disposal system- [44].

The convectional cyclone (1) separates the sand from the produced fluid; this

fluid moves into a surge tank where they are transported to a shore facility via

pipeline. The separated sand settles in the silt pot below each cyclone, where

they are forced out by differential pressure. The centrifugal pump (2) then

supplies water to the sand which moves it to the collection trough.

The two phase mixture of sand, water, and oil moves to the classifier vessel (3)

where the sand and free water moves to the bottom and top of the cone

respectively due to the difference in their density. The adjustable regulator (4)

helps to control the vessel pressure by venting gas to the surge tank.

The dump valve (6) is actuated by both the water level control (5) and the oil

level control (7) which maintains the level of the water in the vessel and also

discharges the oil to the surge tank. Both the mixture of water and sand moves

to No. 1 cyclone (9) of the sand washer at the opening of the dump valve

(6).The cyclone separates the sand to the sand washer while the water and free

oil goes to the separation vessel (10) through the cyclone overflow line (11).



Figure 5.1: Sand Removal, Transporting and Cleaning System on the Grand Isle 16L Platform by Exxon Company U.S.A



Fig 5.2 refers to the separator where the water and the oil are allowed to

separate to the bottom and top respectively due to their difference in density.

The water acts as a source for the recirculation pump (2), while the cyclone

banks (1) acts as both an entry and exit point for the water. It was also

observed that as the sand exit the cyclone banks (1), both water and oil comes

out with it.

The classifier (3) removes the excess oil while water and sand goes to the sand

washer No 1 cyclone (9). The equality of both the amount of water that is being

separated and discharged by the cyclone banks (1) will keep the volume of re-

circulation constant; otherwise the volume will continually fall. The high level

controller automatically opens the dump valve (15) when it senses an increase

in the water level at the separator where the water is discharged into the sump

tank-[44].

5.4.1.2.2. Mode of operation for the sand washer

As illustrated in Figure 5.3, the mixture of water, sand and oil moves into the No

1 cyclone (9) from the classifier vessel (3). The sand is separated from the

mixture and moves to No 1 compartment (3) of the sand washer while the

mixture of the oil and water flows to the separation vessel (10).The gas line

prevents air from entering the cyclone as it internally spins the fluid. In the

centre vortex, gas is mixed with the separated fluid where they get to be

deposited in the separation vessel (10).

From the compartment, the sand moves to the suction end of the No 1 pump

where sand cleaning chemicals are added. Sand, water and the chemicals then

moves to the No 2 cyclone (33) where the actual washing and separation takes

place. Through the overflow line (35) the oil, water with the dispersed air moves

to Compartment 30 while the sand is discharged into compartment 34 which is

then introduced into No 3 Cyclone (37)

While the sand moves into the flush troughs (38), the water returns back to the

compartment (34). Sea water then enters into the flush trough, and also the

compartment where the sand is carried to the gulf. The valve rotometer (45 and

46) regulated the volume in each container, while the sand is collected at the

bottom of the separation compartment



Figure 5.2: Schematic Diagram for the Separation Vessel for Exxon Company U.S.A



Figure 5.3: Schematic Diagram for the Sand Washer.



Table 5.1 below illustrates the problem encountered on Grand Isle Block

Platform and possible solutions-[44].

Table 5.1: Problems and Solution for Grand Isle Block 73 A-D Platform

S/N Problems Encountered Possible Solution

1 Erosion occurred due to the

wearing of the cone and

leakages in pump which

resulted in the failure of the

unit within two months of

operation.

Cone erosion can be reduced by

substituting the rubber liners with highly

reliable polyurethane liners.

2 Leaking/ wearing of the shaft

occurred due to the migration

of sand from the pump.

Regular replacement of the liners and

packing’s.

3 A major pump failure occurred

after 10 months of operation

which was caused by the

combination of erosion and

corrosion.

Ceramic coated plastic sealed housing

can be used to handle the issue of both

corrosion and erosion. Ceramic has a

high resistance to erosion but susceptible

to corrosion while the plastic material on

the other hand is not resistance to

erosion but prevents the fluid from having

surface contact with the coated metals

thereby preventing corrosion

4 Sulphate reducing bacteria

growth began to surface

around the stagnant corners

of the sand washer. This was

due to the usage of sea water

that contained a lot of

bacteria.

Continuous injection of water between

the gland and the seal section of the

pump

5.4.2. Case Study 2

The installation of a sand separation and Handling System at the South Pass 78

field



5.4.2.1. Background Story

South pass 98 field is sited in the Gulf of Mexico oil production facility and has

41 production wells. They encountered operational problems during production

such as: emulsion stabilization, erosion and equipment plugging. These

occurred as a result of continuous passing of produced solid through a

corrugated plate interceptor, which led to a decline in the efficiency of the

separator-[16].

5.4.2.2. Design of the Gulf of Mexico Sand Handling System

A sand handling system had to be designed with the main aim of separating the

maximum amount of solid from the mixture of oil and water. They designed a

system (Fig 5.4) that followed the five basic steps for the design of a general

solid handling system has explained in section 4.7. It had the following features

Simple to operate and requires minimum human intervention

A pressure drop of 40psi with a minimal footprint.

Figure 5.4: Process Layout of Oil and Gas Water De-Sanders with Integral

Solids Dewatering and Haulage System. Taken from-[16] .



The five basic steps include:

5.4.2.2.1. Separation

The separation of the sand from the mixture of oil and water was carried out

with the aid of similar size liner style de-sanders. Each of the de-sanders unit

was positioned at the different outlet stream of the LP separator. The de-

sanders were made from a mixture 316 stainless steel liner plates, carbon steel

and alumina ceramic liners.

The de-sanders helped in ensuring that a constant pressure drop was

maintained at a constant rate by acting as a fixed size orifice. Its bypass loop

prevents shutdown during maintenance. The pressure indicator was used to

monitor the operation, while the separated solid moved into the sand

accumulator section. Table 5.2 below shows the operating parameters of the oil

and water de-sander.

Table5.2: Operating Parameters of South Pass 78 De-Sanders. From-[16] .

OPERATING PARAMETER

Design flow rate for water de-

sander

20,000B/D

Design flow rate for oil de-sander 15,000B/D

De-sander diameter 1.5in

Base dc 7µm

Correction factor for sand in water 500ppm

Correction factor for sand in oil 100ppm

Pressure drop 40psi for each stream

In –situ liquid viscosity for water 0.64cp

In –situ liquid viscosity for oil 2.0cp

Total solid recovery >99%

5.4.2.2.2. Collection

The accumulator is an essential part of the de-sander vessel; operating at the

same pressure with the vessel. The sand level switch which is a thermal

dispersion probe occupies two third of the height of the separator. It helps to

purge the sand at the same time acting as a protector against sand slugs in the



de-sander. The rate at which the sand was collected depending on a 10 second

purge, is shown in the Table 5.3 below

Table 5.3: Purge Rate/Liquid Loss of South Pass 78 De-Sanders.

Water De-sander Oil De-sander

Process data

Liquid flow rate(B/D) 13,650 15,000

Solid concentration(ppm) 100 50

Accumulator sizing

Underflow volume (ft≥) 6.1 6.1

Volume of sand (ft≥) 3.0 3.0

Dumps per day 5 2

Time between

dumps(minutes)

288 774

Purge discharge

Purge time(seconds) 10 10

Pressure(psia) 85 85

Slurry discharge(gal) 179 198

Liquid volume

discharge(ft≥)

20.9 23.4

Bin loading

Total bin volume(ft≥) 0 87

Available solids, weight

(lbm)

0 6,763

Total solid per day (lbm) 0 1,591

Time to fill bin,

weight(hours)

0 102

5.4.2.2.3. Cleaning

Although this stage was not needed for this particular operation because all

produced solids were taken onshore for proper disposal. On a general note this

stage ensures the removal of adsorbed oil from the sand particles. It employs

the principle of mechanical agitation which scrubs oil coating from the sand-[16].



5.4.2.2.4. De watering

Dewatering was done to the reduce the volume of liquid that comes with the

slurry (3ft3 sand and 21ft3 of liquid) from the accumulator. Although the use of

filters where the solid are placed in the bin is the common practise, a novel

method was used which involves the use of Stock DOT approved transport

bins-[16].

5.4.2.2.5. Haul aging

Due to the environmental restriction, the disposal of solid was done in a facility

that was approved by the Louisiana Commissioner of Conservation. The sands

were packed into a DOT transport bins and then moved to the shore via a

transportation vessel, where they were disposed in an approved landfill via a

flatbed truck-[16].

5.4.2.3. Mode of operation of the de-sander

The desander carried out its function via the following steps-[16], as listed

below:

It starts operation once the fluid is passed through it and the required

pressure drop has been attained. The pressure drop within a certain

band determines the efficiency of the unit and also changes in proportion

with the flow rate. For greater efficiency, the pressure drop should remain

at its maximum.

The design pressure drop for the unit is 40psi. If this pressure reduces to

10psi, it is recommended to change the quantity of the liners. The

minimum pressure drop is 5psi which is attained when the system is at

the shutting down level. Although there is no theoretical maximum

pressure drop, 75psi is often recommended.

The disk valve always opens every 10 seconds, and then closes. It is

very important for this valve to be open long enough to empty the de-

sander but care has to be taken so that drainage of excess liquid to the

collection bin does not occur.

The dumped slurry is taken to the sand DOT bins, which through the

porous standpipe drains the liquid while the sand is being retained. The

bin continuously receives this slurry at regular interval until it reaches a

gross limit of 7,700lbm and a tare weight of 1,100lbm.



The sand DOT is usually isolated by closing both the inlet and the outlet

valves once the sand DOT Bin is full. The bin is removed by a crane,

while the transport lid replaces the operation lid which is kept on stand-

by.

Table 5.4: Problems and Solutions on the South Pass 78 Field

S/N Problems

Encountered

Likely Cause Solutions

1 During the initial stage

of operation, the

pressure drop of the

de-sander was within

the range of 30 - 35psi,

which steadily

increases to 45psi

when different levels of

surges were

experienced.

High flow rate was

suspected to be the

cause, as the start-up

flow rate was

13,500B/D, while the

measured flow rate was

16,000B/D.

Four blanks were

replaced with active

liners which reduced

the pressure drop to

35psi.

2 The dump valve

refused to operate

automatically, even

though the sand level

was found to be 3 inch

above the sand probe.

The probe calibration of

the valve was done with

tap water and beach

sand as produced solid

were not available

during the time of

calibration

The valve was first

calibrated with a

sample of sand that

was collected from

the de-sander

underflow. It was

then put back into

operation where it

worked more

effectively.

3 After several weeks,

high pressure drop

was again experienced

at the water de-sander.

This was solely due to

the addition of more

wells

An ultrasonic flow

meter was used to

measure the flow rate

of both the inlet and

the outlet where a

new flow rate was



established as

20,000B/D. All blanks

in the system were

also replaced with

active liner

4 Drainage problem

surfaced at the DOT

(Department of

Transport) bin.

Inspection was carried

out on the bin intervals

and connections, where

it was observed that the

flexible drain hole was

too long and was badly

located, resulting in a

10-12ft drop below the

sump level, this brought

about back pressure to

the bin.

The hose was re-

located, and later

inspected for

blockage

5 Plugging of the drain

screen was observed

this was due to the

presence of big particles

of sand

Tapping of the hard

drain pipe proved as

a temporarily

solution, while the

instalment of two

different sized

pneumatic vibrator

directly below the bin

proved as a

permanent solution.

6 Dump valves opens

without any indication

of liquid flow

The drained pipe was

filled with sand, caused

by insufficient slope in

the drain pipe allowing

the sand to accumulate

in the drain line.

Slight slope was

added to the drain

line that assisted in

the flow of slurry.



5.4.3. Case Study Three

The Installation of new generation desander system at the Albacora deep water

field in Britain.

5.4.3.1. Keeping Up With Sand Production

The Albacora field composed of sixty- five wells with two production units. The

production unit includes a semi- submersible platform and a Floating Production

Storage and Offloading (FPSO) platform. During the production of oil and gas,

they experience a decline in both the residence time and the rate of production.

Series of investigations were carried out where it was observed that the

recession was caused due to the accumulation of sand in the production

separator as shown in the figure 5.5 below-[43].

Figure 5.5: Sand Accumulation in Production Separator. Taken from [43]

In addition erosions of pumps, valves and other accessories were experienced,

which led to the shutting down of the plant at regular intervals. More bills were

incurred for clean out, labour and disposal cost.

The new generation de-sander system was installed on both platforms where a

field test was carried out to verify the reliability of the system and also to ensure

that no form of emulsion or solid entrainment will occur. Table 5.5 below shows

the specifications of the de-sanding system.



Table 5.5: De-Sanding System Specification. Taken from-[43] .

Outflow of Circulation 5,000 bbld

𝒅𝒑of Pump 70 psi (4.9 bar)

Capacity of Delivery 5,000 bbld

𝒅𝒑of Eductors 42 psi (2.9 bar)

Capacity of De-sander 5,000 bbld

𝒅𝒑 of Desander 12 psi (0.8 bar)

Capacity of Solids Recovery Vessel 145 L

5.4.3.2. Pilot Study Result

The separation efficiency was 90% which eliminated the need for a

regular shutting down of the system, during the separation process.

The amount of oil lost during the separation process was very

insignificant

The amount of solid separated by the de-sander was as much as 145

litres per shift

The amount of solid that was left at the bottom of the separator after the

testing period was very insignificant as compared to that being retained

by other convectional method.

It overall led to an annual gain of USD 1,553,000 per platform

The outcome of the test showed that both objectives were met, which confirmed

it to be both a reliable and effective method of sand disposal.

5.4.4. Case Study Four

The Application of Integrated Sand Cleanout System at the Dagang

Oilfield in China, 2006

For demonstration purpose, the integrated sand cleanout system was applied to

Dagang Oil field with the following physical and production parameters as

shown in the table 5.6 below

Table 5.6: Physical and Production Parameters of Dagang Oil Well-[35].

Parameter Unit Value Parameter Unit Value

Reservoir depth

m 2250 Tubing inner diameter

mm 76.9

Plug back total

depth

m 2250 Sand density Kg/m3 2850

Formation MPa 20 Density of the Kg/m3 1000



pressure working/carrier fluid

Bubble point

pressure

MPa 10 Viscosity of the

working/carrier fluid

m.Pa.s 1

Casing outer

diameter

mm 127 Pump depth m 2480

Casing inner

diameter

mm 111 Depth of the sand

pavement

m 2490

Tubing outer

diameter

mm 88.9 Productivity index

m3

/MPa/d 2

Several conventional methods have previously been applied, but had failed due

to the following reasons.

Excessive leakage of the working fluid into the formation.

Stoppage of production process during the separation process.

In the year 2006, the integrated sand cleanout system was applied, where water

was used as the working fluid, with the following parameters.

The diameter of the cleanout pipe is 60mm

The diameter of the jetting nozzle is 1.95mm

The median grain diameter of the sand particle is 0.32mm

The percentage of sand particles with diameter less than 0.50mm is 95%

It was then decided to find a means of lifting the sand particle with diameter less

than 0.50mm upward. The ultimate sand velocity can be calculated from

equation 5.1 below.

𝑢𝑠 = 0.078 − 0.357𝑢𝑙 ⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛 5.1

Table 5.7 shows the operation parameters for the integrated sand cleanout

system

Table 5.7: Designed Operation Parameters of Dagang Oil Well. From - [35].

Parameter Unit Value Parameter Unit Value

Flow rate of the

working

m3 /d 416.4 Bottom hole

pressure

MPa 19.80



fluid for the carrier fluid

Flow rate of carrier

fluid

m3 /d 138.6 Wellhead back

pressure

MPa 0.49

Flow rate of power

fluid

m3 /d 277.8 Wellhead pressure of the working

fluid

MPa 11.42

12 mm 3.46 Power fluid pressure at

the jet pump intake

(nozzle)

MPa 34.82

Diameter of the

throat of jet pump

mm 5.47 Suction pressure at the pump

intake (throat)

MPa 19.01

Diameter of the jetting

nozzle of the

cleanout pipe

mm 1.95 Pump discharge pressure

MPa 24.92

Efficiency of the jet

pump

% 29.89 MPa

5.4.4.1. Study Result

During the cleaning operation, it was observed that the amount of the

working fluid that was circulated from the wellbore its equal to the

amount of working fluid that was injected. This means that there was no

significance leakage of the working fluid into the formation.

The total time spent on separation process was roughly 12 hours.

The volume of sand that was brought out from the well was 0.86m3

This new method has been successfully applied where it proved very effective

in trying to prevent the leakage of the working fluid into the formation.



CHAPTER SIX

RECOMMENDATION AND CONCLUSION

6.1. CONCLUSION

This research has been able to present a detailed review on the: parameters

that determine the effectiveness of a well stream separation process, various

mechanism adopted for its separation process, different separation

technologies citing case studies were necessary and particularly outlining the

factors that have to be considered for the suitability of each separation process.

In respect to this, the following points itemised below are findings that are

derived from this research:

The parameters that determine the efficiency of any gas- liquid

separation process are the particle size, gas velocities, the gas-liquid

densities, operating pressure, operating temperature, surface tension,

the number of stages and the absolute handkerchief test.

The various mechanism that governs any gas- liquid separation process

include the use of gravity settling(difference in density), filtering,

coalescence, impingement, change in the direction of the flow, change in

the velocity of the flow, centrifugal force, application of heat, settling,

agitation, baffling and the application of chemicals.

The different gas-liquid separation technology that are currently being

used in the oil and gas industry include the use of a vertical separator,

horizontal separator, spherical separator, gas scrubber, gas liquid

cylindrical cyclone, subsea separation plant, inline technology and

pipeline separation technology.

The operational problems that can arise from a separation process

include the presence of foam, paraffin, wax, solids and the occurrence of

carry over, blow-by, emulsion, hydrates, corrosion and erosion

The different technology that can be used for proper separation, disposal

and handling of solids separation, includes the use of zero sand

production limits, convectional exclusion methodology, inclusion

methodology (de-sanders) and the incorporation of the sand cleanout

systems.



The factors that should be considered for the suitability of each

technology includes: the relative amount of gas and oil in the well

stream, the variation in densities between the liquid and the gas phase,

the variation in viscosities between the liquid and the gas phase, the

operating parameters at which the separation process is to be carried

out, the level of re- entrainment and the concentration of impurities and

other extraneous materials.

A vertical separator should be used to separate reservoir fluids that flow

at a low rate with a high gas-liquid–ratio, an extreme gas-oil ratio, and a

significant amount of solids.

A horizontal separator should be applied to foamy reservoir fluids that

flow at a constant rate, with a high gas- liquid –ratio and a medium gas –

oil ration

Although no longer being produced, a spherical separator should be

used when a small separator is needed and no form of liquid slugging is

to be tolerated.

A gas liquid cylindrical cyclone should be adopted in separation process

that requires a minimum pressure loss, a separation efficiency of

99.9+%, and low cost of maintenance.

A gas scrubber should be used in a separation process that requires the

continuous separation of the liquids and the solids from the gas stream.

A subsea separation plant is used in a cold deep environment where

they can be easily retrievable and replaceable. As seen by the case

study done on the Tordis platform and the Troll C pilot separation

system

Inline separation should be incorporated in a system that requires the

use of a high gravitational force to achieve its separation process.

A pipe separation technology should be incorporated in separation

process that does not require a vessel.

The case study carried out on the Grand Isle 16L production platform

and the south pass 78 field has proved the efficiency of de-sanders in

the separation of solid from the reservoir fluid.



The outcome of the test carried out on the Albacora deep water has

established the feasibility and the effectiveness of the new generation

de-sander system.

The case study carried on the Dagang Oilfield China has proved the

efficacy of the integrated sand cleanout system.

6.2. Recommendations

My recommendations will be directed towards the new separation technologies

which include the subsea, inline and the pipeline separation technology.

6.2.1. Subsea separation technology

As highlighted in section 3.5.4, the limitation of a subsea separation technology

includes its expensive nature which makes it not easily affordable and the

unreliability of the system as a whole.

6.2.1.1. Possible solutions.

The sub-component of a subsea separation process should be designed

in accordance with the American Society of Mechanical Standards. This

will help to prevent any unforeseen incidence and also increase the

reliability of the system

Maintenance and replacement of worn out internal features should be

carried out on a regular basis.

6.2.2. Inline separation technology

Due to the numerous benefits that can be acquired from the inline

separation technology as compared to that of the convectional

separation equipment, it should be incorporated into new and existing oil

and gas field.

6.2.3. Pipeline separation technology

Further studies should be made on the issue of sand handling as this is

still an aspect of this technology that has remained unsolved.



REFERENCES

APPENDIX

SECTION A: Basis for Re-Entrainment in Separators

A.1. Definition and Occurrence

Re-entrainment can be defined as a natural phenomenon that occurs at the

margin between a stratified wavy and an annular phase flow regime as shown

in Figure A.1 below. This phenomenon allows the rifting away of liquid droplets

from the gas /liquid interface.

They appear in the form of waves or ripples and are caused majorly by high gas

velocities, momentum transfer and differences in pressure between the gas and

liquid interface-[45].

Figure A.1: General Multiphase Flow-Regime Map. Taken from-[45] .

[46]&-[47] proffered a correlation that could predict the maximum velocity

necessary to allow re- entrainment of liquid into the vapour phase. As shown in

table A.1 below, it basically involves determining both the Reynolds and

interfacial viscosity number from equation A.1 and A.2 respectively.



𝑁𝑅𝑒𝑓 = 𝜌𝐿𝑣𝐿𝑑𝐻 𝜇𝐿⁄ ⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛 𝐴. 1

𝑁𝜇 =𝜇𝐿

[𝜌𝐿𝜍((𝜍

𝑔Δ𝑝

0.5]0.5

⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯⋯𝑒𝑞𝑢𝑎𝑡𝑖𝑜𝑛 𝐴. 2

Tab A.1: Re- Entrainment Criteria for Maximum Gas Velocity. Taken from - [45].

RE-ENTRAINMENT CRITERIA FOR MAXIMUM GAS VELOCITY

NRef Nµ 𝐕𝐫 𝐦𝐚𝐱

<160 _ 1.5 𝜍 𝜇𝐿⁄ (𝜌𝐿 𝜌𝑔⁄ )0.5 𝑁𝑅𝑒𝑓−1

2

160≤NRef ≤1635 ≤0.0667 11.78 𝜍 𝜇𝐿⁄ (𝜌𝐿 𝜌𝑔⁄ )0.5 Nµ0.8𝑁𝑅𝑒𝑓−1

3

160≤NRef ≤1635 >0.0667 1.35 𝜍 𝜇𝐿⁄ (𝜌𝐿 𝜌𝑔⁄ )0.5 𝑁𝑅𝑒𝑓−1

3

>1635 ≤0.0667 𝜍 𝜇𝐿⁄ (𝜌𝐿 𝜌𝑔⁄ )0.5 Nµ0.8

>1635 >0.0667 0.1146 𝜍 𝜇𝐿⁄ (𝜌𝐿 𝜌𝑔⁄ )0.5

A.2. Mechanisms for the re – entrainment of liquid

The Reynolds number measures the degree of disorderliness in the liquid

phase while the interfacial number Nµ determines the flexibility of the liquid

surface under unstable conditions. Based on this, [46] & [47] proposed three

distinct regimes that are prone to re- entrainment of liquid into the gas phase

A.2.1. Low Reynolds number regime NRef<160

The gas comes in contact with the gas/liquid interface, penetrates it and

forcefully ejects the liquid from the surface-[45].

A.2.2. Transition regime 160≤NRef ≤1635

This is the transition phase between the low and high turbulent area within the

system-[45].

A.2.3. Rough turbulent regime NRef >1635

The tendency of re-entrainment occurring tends to be very high within this

phase because of its high level of un-stability. This phase is governed by

interfacial properties of the fluid-[45].



School Of Engineering Risk Assessment

(Guidance notes to be read prior to completing risk assessment)

PROCEDURE:

Experimenter completes Risk Assessment in consultation with Supervisor and technical staff as appropriate.

Risk assessment is checked and signed by Supervisor

Experimenter scans copy to Safety Advisor

Places a paper copy of the signed document with the lab technician.

Safety Advisor sends copy to School Administrative Officer & academic supervisor

NOTES:

No laboratory work is to commence without a risk assessment signed by the Supervisor.

The risk assessment must be reviewed when any changes are made to the equipment, materials, procedure or personnel.

Technical staff can stop work if no risk assessment is in place or if, in their opinion, there is a risk to safety.

Title of Project

Developing Rational Criteria For Gas /Oil/Water/Sand Separation Methods

Description of Work

To investigate and carry out a review on: the different separation technologies

currently be used in the oil and gas industry principally demonstrating their

suitability for different operational conditions, the parameters that determine the

effectiveness of a separation process, the different procedure used for the

disposal and handling of solid and other extraneous material and the suitability

of each technology mentioned.

Names of Persons Carrying Out Work

Miss Mamudu Angela

Name Of Supervisor

Professor Howard Chandler

Location of Work

University of Aberdeen Campus

Start date 13th June 2012 Predicted end

date

13th September

2012

List of Major Equipment, Materials And Facilities Involved.

Computer

Universal Serial Bus (USB) Flash Drive

Manual Referencing

Project Logbook

Printer



Record Details Of The Hazards And Who Could Be Harmed.

Working with my personal laptop can be very risky - The system can crash

anytime or be stolen which can lead to an abrupt delay in my project.

Relying only on a USB flash drive to save your work can be very risky –the flash

drive can suddenly malfunction which can also lead to me not being able to

meet up with the submission deadline

Manual Referencing- The manual way of referencing without using any

referencing software can lead to a lot of mistakes if one is not 100 percent

careful. This can result into plagiarising an individual work which the university

frowns against

Log book: My log book which contains the daily report of my project has to

continually be kept safe. The misplacement of the logbook can also serve as an

hindrance to the progress of the project

Record The Precautions Which Will Be Taken.

I made sure that my work was stored in my University of Aberdeen home

drive which presently I consider is the safest place to store my work.

I did not only save my work on my USB and home drive, I also saved it in

my mail box

I used Refworks software to carry out my referencing to avoid any form

of mistake and overall plagiarising an individual work

My log book was with always with me as it was the only place I jotted

down new ideas, and when not with me, it is continually kept in a safe

place.

Prepared by Signature Date

Mamudu Angela Onose

5th September 2012

Supervisor Signature Date

Copy with Safety Advisor?

Copy in Laboratory?

(to be retained for 1 year after completion

of work)



REFERENCES

[1] Bergerman S.D, Polderman H.G, Bravo J.L. Shell Separation Technology from the Wellhead to the User 2001;.

[2] Abdel-Aal, H. Aggour, M. Fahim, M. Petroleum and Gas Field Processing. Marcel Dekker: New York, 2003;1358.

[3] Havard D. Oil and Gas Production Handbook. ABB, 2006;122.

[4] Fantoft R, Akdim MR, Mikkelsen R, Abdalla T, Westra R, Haas Ed. Revolutionizing Offshore Production by InLine Separation Technology 2010;.

[5] Steve Worley M, Laurence LL. Oil and Gas Separation is a Science 1957;.

[6] I. A, R J, A., O. S, S. S, E K, G. Hydrodynamics of Two-Phase Flow in Gas-Liquid Cylindrical Cyclone Separators 1996; 1: 427-427-436.

[7] Chirinos W.A, Gomez L.E, Wang S, Mohan R.S, Shoham O, Kouba GE. Liquid Carry-Over in Gas/Liquid Cylindrical Cyclone Compact Separators 2000; 5: 259-259-267.

[8] Stewart M, Arnold K. Chapter 3 - Two-Phase Gas–Liquid Separators. Gas-Liquid and Liquid-Liquid Separators. Gulf Professional Publishing: Burlington, 2008:65-130.

[9] Vernon Smith H. Oil and Gas Separators (1987 PEH Chapter 12) 1987;.

[10] Manning, Francis, S. Thompson, Richard, E. Oilfield Processing of Petroleum: Crude Oil. Penn Well Publishing Company: United State of American, 1995.

[11] Leon K,. Oil and Gas Separation Theory, Application and Design 1977;.

[12] Chilingarian G, Robertsons J, Sanjay K. Surface Operations in Petroleum Production. Elsevier Science Publishers: Netherlands, 1987.

[13] Arnold K, Stewart M, Stewart MI, Stewart MI. Chapter 5 - Oil and Water Separation. Surface Production Operations: Design of Oil-Handling Systems and Facilities (Second Edition). Gulf Professional Publishing: Woburn, 1999:135-159.

[14] Sanjay K. Contributions in Petroleum Geology and Engineering. Gulf Publishing Company: Houston, Texas, 1987.

[15] Lu Y, Greene JJ, Agrawal M. CFD Characterization of Liquid Carryover in Gas/Liquid Separator with Droplet Coalescence due to Vessel Internals 2009;.



[16] Rawlins CH, Staten SE, Wang II. Design and Installation of a Sand Separation and Handling System for Gulf of Mexico Oil Production Facility 2000;.

[17] McALEESE S. Operational Aspects of Oil and Gas Well Testing. Elesevier: The Netherlands, 2000.

[18] Brito A, Trujillo JN. Viscosity Effect in Cyclone Separators Performance 2009;.

[19] Kouba GE, Wang S, Gomez LE, Mohan RS, Shoham O. Review of the State-of-the-Art Gas/Liquid Cylindrical Cyclone (GLCC) Technology—Field Applications 2006;.

[20] Campbell J, M. Gas Conditioning and Processing. Campbell Petroleum Series: 199USA, 1992.

[21] Mokhatab S, Poe W. Handbook of Natural Gas: Transmission and Processing. Gulf Professional Publishing: USA, 2006.

[22] Erdal FM, Shirazi SA, Mantilla I, Shoham O. Computational Fluid Dynamics (CFD) Study of Bubble Carry-Under in Gas-Liquid Cylindrical Cyclone Separators 2000; 15: 217-217-222.

[23] Movafaghian S, Jaua-Marturet JA, Mohan RS, Shoham O, Kouba GE. The Effects of Geometry, Fluid Properties and Pressure on the Hydrodynamics of Gas–Liquid Cylindrical Cyclone Separators. International Journal of Multiphase Flow 2000; 26: 999-1018.

[24] Fantoft R, Hendriks T, Chin R. Compact subsea separation system with integrated sand handling 2004;.

[25] Strømquist R, Gustafson S. SUBSIS — the World's First Subsea Separation and Injection System. World Pumps 1999; 1999: 33-36.

[26] Alary V, Marchais F, Palermo T. Subsea Water Separation and Injection: A Solution for Hydrates 2000;.

[27] Vu VK, Fantoft R, Shaw CK, Gruehagen H. Comparison Of Subsea Separation Systems 2009;.

[28] Fantoft R, Hendriks T, Elde J. Technology Qualification for the Tordis Subsea Separation, Boosting, and Injection System 2006;.

[29] Baxter T. Subsea Process Technology, Lecture Slides EG55F8/G8;"Subsea Engineering Flow Assurance". University of Aberdeen: Scotland, 2012.

[30] Horn T, Eriksen G, Bakke W. Troll Pilot- Definition, Implementation and Experience 2002;.



[31] Horn T, Bakke W, Eriksen G. Experience in operating World's first Subsea Separation and Water Injection Station at Troll Oil Field in the North Sea 2003;.

[32] Schook r, asperen v.v. Compact separation by Means of Inline Technology 2005;.

[33] Kremleva E, Fantoft R, Mikkelsen R, Akdim MR. Inline Technology—New Solutions for Gas/Liquid Separation 2010;.

[34] Rawlins CH, Hewett TJ. A Comparison of Methodologies for Handling Produced Sand and Solids to Achieve Sustainable Hydrocarbon Production 2007;.

[35] Chen S, Yang D, Zhang Q, Wang J. An Integrated Sand Cleanout System by Employing Jet Pumps 2007;.

[36] Al-Baggal ZA, Al-Refai I, Abbott JW. Unique Expandable Sand Screen and Expandable Liner Hanger Completion for Saudi Aramco 2006;.

[37] Buren Mv, Broek Lvd, Whitelaw C. Trial of an Expandable Sand Screen to Replace Internal Gravel Packing 1999;.

[38] (Bill) Ott WK. Selection and Design Criteria for Sand Control Screens 2008;.

[39] Gillespie G, Beare SP, Jones C. Sand Control Screen Erosion- When are you at Risk? 2009;.

[40] McReynolds PS. Gravel Packing Controls Unconsolidated Sand in Venezuela Field 1958;.

[41] Kotlar HK, Moen A, Haavind F, Strom S. Field Experience With Chemical Sand Consolidation as a Remedial Sand Control Option 2008;.

[42] C D, J., E H, M. The Separation of Solids and Liquids with Hydrocyclone-Based Technology for Water Treatment and Crude Processing 1994.

[43] Coffee S.D. New Approach to Sand Removal 2008;.

[44] A. G, Juan. A System for Removing and Disposing Of Produced Sand 1974; 26: 450-450-454.

[45] Viles JC. Predicting Liquid Re-Entrainment in Horizontal Separators 1993; 45: 405-405-409. [46] Ishii M, Grolmes MA. Inception Criteria for Droplet Entrainment in Two-Phase Concurrent Film Flow. AIChE Journal 1975; 21: 308-318. [47] R. R, I. S, S. S,. Comparison of Multiphase-Flow Correlations with Measured Field Data of Vertical and Deviated Oil Wells in India (includes associated paper 20380) 1989; 4: 341-341-349.

Documents

DEVELOPING RATIONAL CRITERIA FOR GAS/OIL/WATER/SAND …ewemen.com/wp-content/uploads/2016/03/Mamudu-A.O._M.Sc... · 2016. 3. 31. · MAMUDU ANGELA, B. Eng. Chemical Engineering. A