DEVELOPING RATIONAL CRITERIA FOR GAS/OIL/WATER/SAND SEPARATION METHODS

Transcription

1 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)

2 PLAGIARISM AWARENESS DECLARATION FORM. DATE RECEIVED: 13 TH SEPTEMBER 2012 SUPERVISOR: PROFESSOR HOWARD CHANDLER 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: Date submitted: 13 TH 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: 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: 13 TH SEPTEMBER 2012 Mamudu Angela Onose Page ii

3 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 iii

4 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 iv

5 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 v

6 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 Well Fluid Separators Modifications Research Intent Scope of Work Research Justification Educational Sector Industrial Sector Thesis Structure..4 CHAPTER TWO: FUNDAMENTALS ON OIL AND GAS SEPARATOR 2.1. The Importance of a Separating Process Definition of Oil and Gas Separator Classification of Separators Classification by Operating Pressure Classification Based on Configuration Classification by Application Classification Based on their Function Classification Based on the Number of Phases Classification by Principle Common Component of Oil and Gas Separator Primary phase separation section Secondary/ Gravity Settling Section.15 Mamudu Angela Onose Page vi

7 Mist Extraction or Coalescing Section Liquid Accumulation Section Process Controls Safety Devices Comparison of the Pros and Cons of Oil and Gas Separators Internal Components of Gas-Oil Separators Mist Extractors Vortex Breaker Wave Breakers Inlet Diverters Sand Jets and Drains De-foaming Plates The Operational Procedure of Oil and Gas Separators Primary Stage Secondary Stage Final Segregation Maintenance Procedures for Oil - Gas separators Periodic Inspection Operational Problems in Separator Foamy Crude Oil Paraffin (Wax) Corrosion/Erosion Estimated quantities of separated fluid Crude Oil Separated Water Gas Measurement of Effluent Fluid Quality...30 CHAPTER THREE: OIL AND GAS SEPARATION THEORY 3.1. Factors that Influences the Efficiency of a Separation Process Particle Size Gas Velocities Gas and Liquid Density Operating Pressure Operating Temperature...32 Mamudu Angela Onose Page vii

8 Surface Tension Number of Stages Stain /Handkerchief Test Principles Used in the Separation of Oil from Gas Centrifugal Force Density Difference (Gravity Separation) Filtering Coalescence Impingement Change in Flow Direction Change in the Velocity of the Flow Principles Used in the Separation of Gas from Oil Heat Settling Agitation Baffling Chemicals Improvement on the Gas-Liquid Separation Technology Gas Liquid Cylindrical Cyclone Diverging Vortex Separators Gas Scrubbers Subsea Separation Factors Considered During the Designing Stage Features of a Subsea Separator Advantages of Subsea Separation Potential Drawbacks of Subsea Separation The Subsea Separation Concept Disposal of the Produced Water The Subsea Sand Handling System Application of Subsea Separation System Case 1: Tordis Subsea Separation Boosting and Injection System Case 2: The Troll C Separation System Inline Separation Technology Advantages of Inline Separation Technology Inline Gas Liquid Separation Inline Liquid -Liquid Separation...54 Mamudu Angela Onose Page viii

9 Inline Sand Separation Pipe Separations...55 CHAPTER FOUR: SOLID SEPARATION, DISPOSAL & HANDLING SYSTEM 4.1. Background Study Sources of Solids Natural Source Artificial source The Effects of Produced Sand Techniques Used in the Disposal of Sand Production Limit Convectional Exclusion Methodology Inclusion Methodology Integrated Sand Cleanout System Structure and Principle Mode of Operation Sand Transportation Behaviour Effect of Sand Interference Settling Effect of Sand Particle Shape Desander (Solid Liquid Hydro Cyclone) Types of Desander Selections and Applications of Desanders Components of a Desander Mode of Operation of a Desander Description of a Surface Facilities Sand Handling System Separation Collection Dewatering Haul-aging New Generation De-sander System Features Mode of Operation...68 CHAPTER FIVE: SUITABILITY OF THE TYPES OF TECHNOLOGY 5.1. Rational Criteria for Gas/Oil/Water/Sand Separation The Separation of Oil from Gas Mamudu Angela Onose Page ix

10 Vertical Separator Horizontal Separator Spherical Oil and Gas Separators Gas Liquid Cylindrical Cyclone Gas Scrubbers Subsea Water Separation Plant & Integrated Solid Handling System Inline Separation Technology Pipe Separation Technology The Separation of Solid and Other Extraneous Material Production Limits Principle Conventional Exclusion Technology Methodologies Used By Companies for the Disposal of Sand Case Study One Case Study Two Case Study Three Case Study Four...88 CHAPTER SIX: CONCLUSION AND RECOMMENDATION 6.1. Conclusion Recommendations Subsea Separation Technology Inline Separation Technology 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< A.2.2. Transition Regime 160 NRef A.2.3. Rough Turbulent Regime NRef > SECTION B School of Engineering Assessment Form...96 List of References 98 Mamudu Angela Onose Page x

11 LIST OF FIGURES FIGURE HEADING PAGE 1.1: Classification of Components Found In Wellhead Fluid : Curve for Development Ranking Of Separation Technology : Classification of Separators : Gas-Oil Separator Train : Schematic Diagram of a Three Phase Vertical Separator : Schematic Diagram of Horizontal Three Phase Separator : Spherical Separator : Main Equipment for a Test Separator : Stage Separator Flow Diagram : Typical Horizontal Two- Barrel Filter Separator : Two Phase and Three Phase Vertical Separator : Schematic Outline of the Main Component in a Gas-Oil Separator : Vane-Type Extractor with Corrugated Plates : Knitted Wire Mist Extractor : Blade Type Mist Extractor : Centrifugal Mist Extractor : Outlet Vortex Breaker : Inlet Diverters : Horizontal Separator Fitted With Sand Jets and Inverted Trough : De-Foaming Plates : Centrifugal Forces Acting On a Particle in A Gas Stream : Forces Acting On A Particle in A Gravity Settling Chamber : Coalescing Process in the Media : The Principle of Impingement, Change Of Direction and Velocity : Two-Step Mechanism of Separating Gas from Oil : Gas-Liquid Cylindrical Cyclone Configuration : Vertical Three Phase Separator acting on Centrifugal Force : Diverging Vortex Separator : Centrifugal Gas Scrubber : Subsea Water Separation Plant with an Integrated Solid Handling...42 Mamudu Angela Onose Page xi

12 3.11: Tordis Subsea Separation System : Process Overview of the Tordis SSBI : Troll C Pilot Separation Plant : Troll C Sand Removal System : Gas Unie TM : Inline Phase Splitter Gas- Liquid Separation Technology : Schematic Representation of a Degasser : Schematic Representation of a De-Liquidiser : Inline Demister Spiraflow : Inline De-liquidiser BP-ETAP : Key Advantage of Inline Liquid- Liquid Separation : Inline Sand Separation : Pipe Separation Concept : Wire Wrapped Screen : Expandable Sand Screen Construction : Metal Mesh Screen Assembly : Open Hole Gravel Pack : Schematic of the Surface Subsystem : Schematic of the Underground Subsystem : Schematic of the Vessel Style De-Sander : Liner Style De-Sander : Dewatered Solids Removal : Decision Diagram Showing -Outline of Solids- Handling System : Solids Collection Vessel : An Educator : Sand Handling System for Exxon Company U.S.A : Schematic Diagram for the Separator of Exxon Company : Schematic Diagram for the Sand Washer : Process Layout of Oil and Gas Water De-Sanders : Sand Accumulation in Production Separator...87 A.1: General Multiphase Flow- Regime Map...94 Mamudu Angela Onose Page xii

13 LIST OF TABLES TABLE HEADING PAGE 2.1: Comparison of Oil and Gas Separators : Estimated Quality of Separated Crude Oil : Estimated Quality of Separated Water : Estimated Quality of Separated Gas : Measurement of Effluent Fluid Quality : Separator Vessels Dimensions -Different Separator Concept : Characteristics of Gas/Liquid Separation Equipment : Physical Properties of Natural Solids Physical Properties of Artificial Solids : De-Sander Selection Criteria : Problems & Solution for Grand Isle Block 73 A-D Platform : Operating Parameters of South Pass 78 De-Sanders : Purge Rate/Liquid Loss of South Pass 78 De-Sanders : Problems and Solutions on the South Pass 78 Field : De-Sanding System Specification : Physical and Production Parameters of Dagang Oil Well Designed Operation Parameters of Dagang Oil Well...89 A.1 Re- Entrainment Criteria for Maximum Gas...89 Mamudu Angela Onose Page xiii

14 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 η mes η vane η T esp Separation Efficiency of a Mesh Pack (dimensionless) Separation Efficiency of a Vane Pack (dimensionless) Target Collection Efficiency of a Single Wire (dimensionless) Exponential V T Terminal Velocity (ms 1 ) m Number of Bends W Width of a Vane Baffle V G Gas Velocity ms 1 ) b Space between Adjacent Vane Blades (m) C D Drag Coefficient ρ G Gas Density (kgm 3 ) V A Actual Gas Velocity (ms 1 ) A P Projected Area of a Vane Blade (m 2 ) Mamudu Angela Onose Page xiv

15 A C Cross Sectional Area of a Vane Pack (m 2 ) P vane H ԑ PVC gal MMscf mm R E d Pressure Drop across Vane Pack (Pa) Thickness of Mesh Pad (m) Void Fraction of a Mesh Pad (dimensionless) Polyvinyl Chloride Gallon Million Standard Cubic Feet Millimetre Droplet Reynolds Number (dimensionless) Circular Pipe Diameter (m) v Velocity (ms 1 ) ρ Density (kg m^3 ) HR Hydraulic Radius WP Wetted Perimeter API American Petroleum Institute O f cp BS&W ppm S C Degree Fahrenheit Centipoise Basic Sediment and Water Parts per Million Chapter Three: Oil-Gas Separation Theory Separator Capacity ρ L Density of Liquid (kg m^3 ) ρ g Density of Gas (kg m^3 ) sec Second π Pi ( ) Height of Centrifuge (m) q Volumetric Rate C d bwpd bopd bbl/d US$ CAPEX OPEX Drag (friction) Coefficient Barrels of Water per Day Barrels of Oil per Day Barrels per Day United State Dollar Capital Expenditure Operating Expenditure Mamudu Angela Onose Page xv

16 S i 0 2 Chapter Four: Solid Separation, Disposal and Handling System Silicon Dioxide ppmv Part per Million by Volume u s0 μ U s K m λ m D p g c Ṽ lbm ANSI LP B/D DOT USD MPa Kg/m 3 N Ref d H Free Ultimate Sand Settling Velocity Viscosity Terminal Settling Velocity of Particle Stokes Cunningham Correction Factor (dimensionless) Mean Free Path of Gas Molecules (ft.) Diameter of Spherical Particles (ft.) Conversion Factor, 32.17(LB. Mass/LB.Force) Mean Molecular Speed, ft. /sec Pound Mass American National Standards Institute Chapter Five: The Suitability of the Different Types of Technology and Possible Solutions to Problems Encountered Low Pressure Barrel per Day Greater Than or Equal to Department of Transportation United State Dollar Mega Pascal ( Pa) Kilogram per Cubic Metre Appendix Section A: Basis for Re-entrainment in Separators Reynolds Film Number (dimensionless) Liquid Hydraulic Diameter (ft.) ρ L Density of Liquid (kg m^3 ) N μ v L Interfacial Viscosity Number (dimensionless) Velocity of liquid (ft/sec) ς Surface Tension between Liquid and Gas (lbm/ft 3 ) μ L Dynamic Liquid Viscosity (lbm/ft-sec) Mamudu Angela Onose Page xvi

17 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]. RESERVOIR FLUID HYDROCARBON WATER SOLID LIGHT GROUP (C1/C2) INTERM EDIATE GROUP (C3-C6) HEAVY GROUP (C7+) FREE WATER EMULSI FIED WATER SAND SILT AND CLAY 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. Mamudu Angela Onose Page 1

18 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] 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]. Mamudu Angela Onose Page 2

19 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 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 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. Mamudu Angela Onose Page 3

20 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 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 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 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 Mamudu Angela Onose Page 4

21 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. Mamudu Angela Onose Page 5

22 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 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] Classification of Separators Figure 2.1 below illustrates the general classification of oil and gas separators. CONFIGURATION VERTICAL, HORIZONTAL AND SPHERICAL SEPARATOR OPERATING PRESSURE LOW PRESSURE, MEDIUM PRESSURE AND HIGH PRESSURE SEPARATOR SEPARAT ORS PHASES TWO PHASE UNIT AND THREE PHASE UNIT APPLICATION LOW TEMPERATURE, TEST AND PRODUCTION PRINCIPLE IMPINGEMENT, GRAVITY, COALESCENCE AND CENTRIFUGAL FORCE Figure 2.1: Classification of Separators Mamudu Angela Onose Page 6

23 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 psi. Medium-pressure separators: operates within the range of psi. High-pressure separators: operates within the range of 750-1,500 psi. Figure 2.2: Gas-Oil Separator Train. Taken from-[10] 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 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]. Mamudu Angela Onose Page 7

24 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: 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 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. Mamudu Angela Onose Page 8

25 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: Advantages 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. Mamudu Angela Onose Page 9

26 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 Disadvantages 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 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 include the following: Mamudu Angela Onose Page 10

27 Advantages 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 Disadvantages 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 Classification by application 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]. Mamudu Angela Onose Page 11

28 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] 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] 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] Foam separator They are specially designed to handle the issue of foaming in the separation process-[9] 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]. Mamudu Angela Onose Page 12

29 Classification based on their function 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] 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] 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] 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 psig - [9, 10] 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] 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 Mamudu Angela Onose Page 13

30 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] Classification based on the number of phases Two phase unit Its function is to separate gas from oil in an oil field, or gas from water in a gas field. [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] Mamudu Angela Onose Page 14

31 Figure 2.9: Two Phase and Three Phase Vertical Separator. Taken from-[10] 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 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: 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 wellshaped deflector plate, centrifugal force and a change in the direction of the flow - [2, 5, 9] 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 Mamudu Angela Onose Page 15

32 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] 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] 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: 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]. Mamudu Angela Onose Page 16

33 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] 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 Stabilization of separated fluids Adaptability of varying conditions Flexibility of varying condition Capacity (same diameter) Cost per unit capacity Ability to handle foreign material Ability to handle foaming oil Adaptability to portable use Ease of installation Ease of inspection and maintenance Mamudu Angela Onose Page 17

34 Space required for installation Vertical Horizontal Most favourable; (2) Intermediate; (3) Least favourable 2.6. Internal Components of Gas-Oil Separators 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: 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] 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 Mamudu Angela Onose Page 18

35 The collection efficiency and the pressure drop across a vane type extractor- [15] can be derived from equation 2.1 and 2.2 respectively. η mes = 1 esp V T. m. W. θ V G. b. tanθ equation2.1 P mes = C D. ρ G V 2 A. A p 2A c equation2.2 Figure 2.11: Vane-Type Extractor with Corrugated Plates and Liquid Drainage Trays. Taken from-[13] 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 in, which makes them more flexible and structurally sound-[9, 10, 13] Features The features of a vane type extractor-[10] are listed below: They are designed to remove fine droplet within the range of μm 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. Mamudu Angela Onose Page 19

36 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]. η vane = 1 exp 2 3 π. A. H. η T equation2.3 ΔP vane = f. H. A. ρ GV 2 G 981ε 2 equation 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 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]. Mamudu Angela Onose Page 20

37 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] 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] 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]. Mamudu Angela Onose Page 21

38 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] 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 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] 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]. Mamudu Angela Onose Page 22

39 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 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] 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 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 Mamudu Angela Onose Page 23

40 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] 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 R E = 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 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 Mamudu Angela Onose Page 24

41 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 Maintenance Procedures for Oil - Gas separators 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] 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] High and low pressure control These controls can be mechanical, pneumatic or electrical and helps to regulate the pressure within the system-[9]. Mamudu Angela Onose Page 25

42 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] 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] Operational Problems in Separators There are several operating problems that could occur in a separator system; they are briefly discussed below 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 >40 o, operating temperature of > 160 O f, 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] The effect of foaming The effect of foaming-[9], on both the operations and efficiency of a separator include the following: 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 Solutions The solutions to a foamy crude oil- [11] include the following: Mamudu Angela Onose Page 26

43 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 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] 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 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] 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]. Mamudu Angela Onose Page 27

44 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] 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] 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] Estimated quantities of separated fluid 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 Mamudu Angela Onose Page 28

45 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]. APPROXIMA TE OIL RETENTION TIME(MINUT ES) ESTIMATED FREE (NON SOLUTION) GAS CONTENT OF EFFLUENT OIL (%) * ESTIMATED RANGE OF WATER CONTENT OF EFFLUENT OIL Minimu m Maximu m Minimum(pp m) (%)* * Maximum(pp m) (%)* * 1 to to to to to (*) refers to a percentage of the total oil volume with the gas measured at standard pressure and temperature, while (**) refers to volume basis. [6] 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]. ESTIMATED RANGE OF OIL CONTENT OF EFFLUENT WATER Minimum(ppm) (%)* Maximum(ppm) (%)* WATER RETENTION TIME (MINUTES) 1 to to to to to (*) refers to volume basis 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 Mamudu Angela Onose Page 29

46 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( O F) 0 to to ESTIMATED OIL CONTENT OF EFFLUENT GAS Minimum Maximum (ppm) (gal/m Mscf) (pp m) (gal/mm scf) 0.10* ** 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 Oil in effluent water Water in effluent oil Gas in effluent-oil Oil in effluent gas Solvent extraction/infrared absorbance Ultraviolet absorption unit BS&W monitor (capacitance measurement unit) Nucleonic Densitometer Laser liquid particle spectrometer Mamudu Angela Onose Page 30

47 CHAPTER THREE OIL-GAS SEPARATION THEORY 3.1. Factors that Influences the Efficiency of a Separation Process 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] 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] 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 S C = ρ L ρ g ρ g equation 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]. Mamudu Angela Onose Page 31

48 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] 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] 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] 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] Principles Used in the Separation of Oil from Gas 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]. Mamudu Angela Onose Page 32

49 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 ft/sec-[9]. Although most centrifugal separators are vertically oriented, a horizontal separator with a centrifugal separating element can also carry out the same function Derivation of its droplet velocity Consider a centrifuge of height h, radius R 2, and inner shaft radius R 1, 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 R 2 2 R 2 1 q equation 3.2 For simplicity, the liquid droplet is assumed to be spherical with a uniform diameter of d p. The area projected by the droplet can then be derived from equation 3.3 below. A = π 4 d2 p 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, F d which is due to friction, can be derived from equation 3.4 below Mamudu Angela Onose Page 33

50 F d = 1 2 C dρ g V 2 A equation 3.4 Solving for the droplet velocity, v can be calculated from equation 3.5 below V = [4gd p ρ l ρ g ] 0.5 (3C d ρ g ) 0.5 equation 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[ (ρ 1 ρ 2 )/ρ g ] 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 Mamudu Angela Onose Page 34

51 t = (π 2 L)/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 = πl 4 V equation 3.13 Substitute for v from equation 3.10 into equation 3.13 gives q = (πl/4) [4gd p ρ l ρ g ] 0.5 (3C d ρ g ) 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] 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 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 µm to µm. 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. Mamudu Angela Onose Page 35

52 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] 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] 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] 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]. Mamudu Angela Onose Page 36

53 Figure 3.4: The Principle Of Impingement, Change Of Direction And Velocity. Taken from-[9] 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 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] Mamudu Angela Onose Page 37

54 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] 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] 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] 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] 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 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]. Mamudu Angela Onose Page 38

55 Figure 3.6: Gas-liquid cylindrical cyclone configuration taken from-[23] 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 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] Mamudu Angela Onose Page 39

56 Figure 3.7: Vertical Three Phase Separator Acting On Centrifugal Force. Taken from-[9] 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]. Mamudu Angela Onose Page 40

57 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 % 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]. Mamudu Angela Onose Page 41

58 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] 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 multi- phase 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]. Mamudu Angela Onose Page 42

59 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 Advantages of subsea separation The following are the attractive and appealing benefits of a subsea separation unit 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] 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] 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]. Mamudu Angela Onose Page 43

60 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] 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] 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] Potential drawbacks of subsea separation 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 approximately US$ million and US$ 2-3 million per year respectively- [26] 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] 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. is 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 Mamudu Angela Onose Page 44

61 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 Minimum vessel size inlet device Novel separator concept with gas bypass 15.0m/2.60m 100% 100% 13.5m/2.25m 67% 69% 12.m/2.00m 47% 52% 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 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 Mamudu Angela Onose Page 45

62 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 Application of Subsea Separation System 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 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]. Mamudu Angela Onose Page 46

63 Figure 3.12: Process Overview of the Tordis SSBI. Taken from-[28] Operational procedure It follows the same process as explained in section 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 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 Mamudu Angela Onose Page 47

64 out distance of 3.5km from the Troll C platform and 120m from the subsea template-[29]. In total the unit measures 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] 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 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]. Mamudu Angela Onose Page 48

65 Figure 3.14: Troll C Sand Removal System. Taken from-[31] 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 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 Inline gas liquid separation This is the most matured in- line technology that was first put into operation in the year 2003-[32]. A complete inline gas- liquid separation unit comprises of the following; Mamudu Angela Onose Page 49

66 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] 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] 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 Mamudu Angela Onose Page 50

67 flowing stream and a gas scrubber that further helps to clean the separated gas-[33] 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] 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 de- gasser-[33] 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 Mamudu Angela Onose Page 51

68 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] 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. Mamudu Angela Onose Page 52

69 Table 3.2: Characteristics of Gas/Liquid Separation Equipment. From- [33] GasUnie TM Degasser Deliquidizer Phase Splitter Demister Spiraflow Separation Efficiency Continuous Phase Dispersed Phase Second stage separation Control system required Control Strategy Turndown Ratio Pressure drop Slug handling capacity 90-99% removal of incoming gas 90-99% removal of incoming gas 90-99% removal of incoming gas About 98%* 99% removal of incoming gas Gas or Liquid liquid Gas Gas or Liquid Gas GVF**<10% GVF**<60% LVF***<60% 20&<GVF<95% Gas NA Scrubber Liquid boot NA Marsh Pad YES YES YES N0**** N0 Liquid level Liquid level Liquid level Application _ in GasUnie in scrubber in boot dependent 50% 50% 50% 50% 50% 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 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 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. Mamudu Angela Onose Page 53

70 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] 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] 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]. Mamudu Angela Onose Page 54

71 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 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] Mamudu Angela Onose Page 55

72 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 Sources of Solids There are basically two sources where produced solids can originate from. This includes the natural and artificial source 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 S i 0 2 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 Shape Factor Size Range(µm) Conc. (ppmv) < 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. Mamudu Angela Onose Page 56

73 Table 4.2: Physical Properties of Artificial Solids. Taken From - [34]. Property Fracture sand Corrosion Gravel Pack Products Specific Gravity Shape Factor Size Range(µm) Conc. (ppmv) <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 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 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. Mamudu Angela Onose Page 57

74 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] 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] 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] 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 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 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. Mamudu Angela Onose Page 58

75 Filtration assurance It is equipped with the exact gauge control and gauge spacing which guarantees greater reliability 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 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. Mamudu Angela Onose Page 59

76 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] 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 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]. Mamudu Angela Onose Page 60

77 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] Advantages It reduces the tendency for skin damages due to the free flow of the sand alongside the well fluid-[34] 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 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 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 Mamudu Angela Onose Page 61

78 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]. Mamudu Angela Onose Page 62

79 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] 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]. u s0 = 4gd s ρ s ρ l 3C D ρ 1 equation4.1 Where g is the acceleration due to gravity, m/s 2 ; d s is the diameter of the spherical sand particle, m; ρ s and ρ l are the densities of the sand particle and the working fluid, respectively, kg/m 3 ; and C D is the coefficient of resistance, which is a function of the Reynolds number of the sand particles 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 = u s C S equation4.9 C s is believed to be the volumetric percentage of the sand, within a range of from 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. Mamudu Angela Onose Page 63

80 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]. u sos = αu s0 equation 4.10 Where α is the shape factor of the formation sand particles 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 Types of de-sander There are basically two types of de-sander namely: the vessel and the liner type 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 The liner style They are designed to have multiple liners, where the individual liners have a nominal diameter within the range of inch. They are used for any type of Mamudu Angela Onose Page 64

81 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 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 Large solids(>5mm) Yes No Fine particle recovery(<25µm) No No Yes (>900lbm) ANSI design No Yes Vessel fabricated of any metal Linear available in ceramic Pressure vessel subjected to wear Replaceable wear components Yes No Yes Yes Yes Yes No Yes Mamudu Angela Onose Page 65

82 Components of a de-sander All solid liquid hydro cyclones comprises of four major components namely: the Inlet, overview, cone and tailpipe 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] 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 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] 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] 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. Mamudu Angela Onose Page 66

83 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 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] 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] 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] 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]. Mamudu Angela Onose Page 67

84 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] 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 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 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 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- Mamudu Angela Onose Page 68

85 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 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] 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]. Mamudu Angela Onose Page 69

86 Figure 4.10: Decision Diagram Used to Decide the Outline of Solids Handling System Mamudu Angela Onose Page 70

87 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 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. Mamudu Angela Onose Page 71

88 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 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 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 Gas scrubbers They are selected for separation processes that requires Mamudu Angela Onose Page 72

89 An effective and continuous separation of liquids and solids from a gas stream. No room for maintenance and shutdown 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 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 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 The Separation of Solid and other Extraneous Materials 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. Mamudu Angela Onose Page 73

90 Conventional Exclusion Technology 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 (Wirewrap 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) 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) Different Methodologies Adopted By Companies for the Disposal of Sand and Problems faced 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 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 Mamudu Angela Onose Page 74

91 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] Description of the Process 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). Mamudu Angela Onose Page 75

92 Figure 5.1: Sand Removal, Transporting and Cleaning System on the Grand Isle 16L Platform by Exxon Company U.S.A Mamudu Angela Onose Page 76

93 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 recirculation 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] 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 Mamudu Angela Onose Page 77

94 Figure 5.2: Schematic Diagram for the Separation Vessel for Exxon Company U.S.A Mamudu Angela Onose Page 78

95 Figure 5.3: Schematic Diagram for the Sand Washer. Mamudu Angela Onose Page 79

96 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. 2 Leaking/ wearing of the shaft occurred due to the migration of sand from the pump. 3 A major pump failure occurred after 10 months of operation which was caused by the combination of erosion and 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. Cone erosion can be reduced by substituting the rubber liners with highly reliable polyurethane liners. Regular replacement of the liners and packing s. 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 Continuous injection of water between the gland and the seal section of the pump Case Study 2 The installation of a sand separation and Handling System at the South Pass 78 field Mamudu Angela Onose Page 80

97 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] 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]. Mamudu Angela Onose Page 81

98 The five basic steps include: 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 desanders 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]. Design flow rate for water desander Design flow rate for oil de-sander De-sander diameter OPERATING PARAMETER 20,000B/D 15,000B/D 1.5in Base d c 7µm Correction factor for sand in water Correction factor for sand in oil Pressure drop In situ liquid viscosity for water In situ liquid viscosity for oil 500ppm 100ppm 40psi for each stream 0.64cp 2.0cp Total solid recovery >99% 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 Mamudu Angela Onose Page 82

99 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) Accumulator sizing Underflow volume (ft ) Volume of sand (ft ) Dumps per day 5 2 Time between dumps(minutes) Purge discharge Purge time(seconds) Pressure(psia) Slurry discharge(gal) Liquid volume discharge(ft ) Bin loading Total bin volume(ft ) 0 87 Available solids, weight 0 6,763 (lbm) Total solid per day (lbm) 0 1,591 Time to fill bin, weight(hours) 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]. Mamudu Angela Onose Page 83

100 De watering Dewatering was done to the reduce the volume of liquid that comes with the slurry (3ft 3 sand and 21ft 3 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] 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] 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 desander 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. Mamudu Angela Onose Page 84

101 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 standby. Table 5.4: Problems and Solutions on the South Pass 78 Field S/N Problems Likely Cause Solutions Encountered 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. 2 The dump valve refused to operate automatically, even though the sand level was found to be 3 inch above the sand probe. 3 After several weeks, high pressure drop was again experienced at the water de-sander. 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. 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 This was solely due to the addition of more wells Four blanks were replaced with active liners which reduced the pressure drop to 35psi. 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. An ultrasonic flow meter was used to measure the flow rate of both the inlet and the outlet where a new flow rate was Mamudu Angela Onose Page 85

102 4 Drainage problem surfaced at the DOT (Department of Transport) bin. 5 Plugging of the drain screen was observed 6 Dump valves opens without any indication of liquid flow 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. this was due to the presence of big particles of sand The drained pipe was filled with sand, caused by insufficient slope in the drain pipe allowing the sand to accumulate in the drain line. established as 20,000B/D. All blanks in the system were also replaced with active liner The hose was relocated, and later inspected for blockage 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. Slight slope was added to the drain line that assisted in the flow of slurry. Mamudu Angela Onose Page 86

103 Case Study Three The Installation of new generation desander system at the Albacora deep water field in Britain 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. Mamudu Angela Onose Page 87