COPYRIGHT. Separation Core. Principles and Equipment of Gas-Liquid Separation. By the end of this lesson, you you will will be able be able to: to:

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1 6/20/2017 Learning Objectives Separation Core Principles and Equipment of Gas-Liquid Separation By the end of this lesson, you you will will be able be able to: to: Describe separator applications and common types of separators List the sizing criteria for 2-phase and 3-phase separators Discuss the principles of gas-liquid separation and how they are applied in separator design Describe the effect of inlet piping size and inlet devices on separator sizing List the types of mist extractors and describe typical applications Estimate separator size based on gas-liquid separation criteria 1 1

2 6/20/2017 Why Separation Equipment? Applications Bulk separation of produced fluids Gas scrubbing upstream of compressors, dehydrators and amine systems Removal of entrained chemicals downstream of glycol and amine contactors Removal of fines/dust downstream of solid desiccant dehydration vessels Provide retention time to reduce flowrate fluctuations upstream up pumps and distillation columns and process facilities Meet product sales specifications Separators are a critical, but often overlooked, component in a processing facility Poor separator performance can significantly impair the effectiveness and availability of downstream process equipment which in turn reduces profitability Where Do We Use Separators? 120 F 1200 psig HP 120 F 500 psig To water treating IP 130 F 180 psig LP CM HM 110 F 1200 psig CM CM 150 F 50 psig Degasser 150 F 4 psig TEG Contactor CM CMCM Gas export 2000 psig To Fuel Gas System Electrostatic Coalescer Surge Tank Oil export 1850 psig CM LACT 2 2

3 6/20/2017 Production Separators Can be 2-phase (gas-liquid) or 3-phase (gas-hydrocarbon liquid-water) Fluctuating flows of gas and liquid including slugs Solids, e.g. sand, paraffin, asphaltenes, corrosion products Low to high vapor-liquid ratios Can be vertical or horizontal Vertical usually preferred in higher vaporliquid ratio applications Horizontal usually preferred in lower vaporliquid ratio applications Typical quality of separated streams Liquid in gas: m3/106 sm3 [0.1 to 2 US gal/mmscf] Water in oil: 2-3 vol% or greater Oil in water: ppmv Not typically designed to meet export/sales specifications Scrubbers Example Scrubber Internals Reciprocating Compressor Suction Scrubber 3 3

4 6/20/2017 Scrubbers Flow rate is typically gas with a small amount of entrained liquid Large fluctuations in flowrate are not common Often prevent damage to downstream equipment due to liquid carryover High separation efficiency is critical Often use high separation efficiency internals to remove liquid from gas Typically vertical orientation Very little liquid retention capacity Typical quality of separated streams Liquid in gas: less than m 3 /106 sm 3 [0.1 US gal/mmscf] Filter Separators Horizontal Filter Separators High efficiency removal of small amounts of liquid from gas Gas flows radially from outside to inside of filters and enters a perforated tube in the middle of each filter element Gas flows to right side of the vessel and through a vane-type mist extractor Liquid in gas: less than m 3 /10 6 sm 3 [0.1 US gal/mmscf] First Coalescing Chamber Gas In Inlet Separation Chamber Final Mist Extractor Gas Out Quick Opening Closure Courtesy Pall First Stage Liquid Reservoir Liquid Out Second Stage Liquid Reservoir 4 4

5 6/20/2017 Filter Separators Horizontal Filter Separators High efficiency removal of small amounts of liquid from gas Gas flows radially from outside to inside of filters and enters a perforated tube in the middle of each filter element Gas flows to right side of the vessel and through a vane-type mist extractor Liquid in gas: less than m 3 /10 6 sm 3 [0.1 US gal/mmscf] Quick Opening Closure Courtesy Pall Filter Separators First Coalescing Chamber Gas In First Stage Liquid Reservoir Dirty/Wet Gas Inlet Inlet Separation Chamber Liquid Out Final Mist Extractor Second Stage Liquid Reservoir Liquid Drain Gas Out Clean Gas Outlet Liquid Drain Horizontal Vertical Coalescing Filter Separators Filters High Very efficiency high efficiency removal removal of small of amounts of liquid from gas Gas small flows amounts radially of from liquid outside from gas to inside of filters and enters a perforated tube in the middle Flow enters of each bottom filter element of vessel and Coalescer Filter Gas up through flows to the right filter side elements of the vessel in and Cartridges through a vane-type mist extractor Liquid top of in vessel gas: less than m 3 /10 6 sm 3 [0.1 US gal/mmscf] Clean Gas Outlet Gas flows radially from inside to First Coalescing Gas In Inlet outside of filters Chamber Upper Separation Sump Liquid may be collected in both Chamber bottom and top sections Liquid in gas: less than Final Mist Extractor m 3 /10 6 sm 3 [0.01 US gal/mmscf] Dirty/Wet Gas Inlet Liquid Drain Gas Out Courtesy Pall Quick Opening Closure First Stage Liquid Reservoir Lower Sump Liquid Out Second Stage Liquid Reservoir Liquid Drain 5 5

6 6/20/2017 Typical Governing Criteria for Sizing Separators Typical governing criteria for sizing of various separation equipment: Droplet Removal from Vapor Primary sizing criterion for most separation applications In scrubbers and coalescing filter separators, it is critical to remove liquid droplets from the vapor stream Liquid degassing and reduction of liquid flow variation are not critical Liquid-liquid separation is almost never done Typical Governing Criteria for Sizing Separators Typical governing criteria for sizing of various separation equipment: Droplet Removal from Vapor Liquid Degassing The removal of entrained bubbles in the liquid phase Seldom the primary separation criterion Important in high viscosity liquid phase or when carry under of bubbles interferes with performance of downstream equipment 6 6

7 6/20/2017 Typical Governing Criteria for Sizing Separators Typical governing criteria for sizing of various separation equipment: Droplet Removal from Vapor Liquid Degassing Separation of Liquid Phases Important criterion in 3-phase separation Controls the size of the separator Liquid-liquid separation typically requires a large interface between liquid phases, so horizontal separator is preferred Requires longer liquid retention times, especially with high viscosity hydrocarbon phase Typical Governing Criteria for Sizing Separators Typical governing criteria for sizing of various Slug catchers separation equipment: Droplet Removal from Vapor Liquid Degassing Separation of Liquid Phases Flow Smoothing / Slug Handling Used at the end of multiphase pipelines and in gathering systems where slugging is prevalent due to elevation changes, variations in flowrates, or in systems that operate in a slug flow regime The main sizing criterion is the ability to store the volume of liquid that arrives with a slug and deliver steady flowrate to downstream equipment Surge vessels Designed to store liquid and attenuate flow variations This is often the primary sizing criterion in vessels upstream of pumps and process units that are sensitive to flow variations such as fired heaters and distillation columns 7 7

8 6/20/2017 Typical Governing Criteria for Sizing Separators Typical governing criteria for sizing of various separation equipment: Droplet Removal from Vapor Liquid Degassing Separation of Liquid Phases Flow Smoothing / Slug Handling Other Foaming Increased carryover Typical Governing Criteria for Sizing Separators Interference with separator controls Solids Sand can accumulate in the bottom of the separator reducing liquid retention volume Can cause failure in level control valves due to erosion around the valve plug and seat Typical governing criteria for sizing of various separation equipment: Droplet Removal from Vapor Liquid Degassing Separation of Liquid Phases Flow Smoothing / Slug Handling Other 8 8

9 6/20/2017 Most separators rely on several mechanisms to achieve separation: Gravity settling Centrifugal forces Impaction Coalescence Principle of Gas-Liquid Separation Drag Force of Gas on Liquid Droplet Force Balance: F Gravity = F Drag 4gD P O g vt 3C d g Where: v t = Terminal velocity ρ = Density g = Gravitational acceleration 0.5 C D p = Droplet size C d = Drag coefficient Re p = Reynold s Number μ f = Fluid viscosity d f Re P Re P Dv P t f f 9 1

10 6/20/2017 Typical Separation Application Settling Laws Smaller droplets are more difficult to separate Minimize formation of entrained droplets Provide conditions favorable to droplet coalescence Minimize shear and turbulence Common-Practice vs Theoretical Methods Assumptions Spherical droplets Unhindered settling Uniform gas velocity profile The theoretical approach requires knowledge of the following variables which are difficult to determine a) Droplet size distributions, which typically change due to shear/coalescence effects b) The amount of entrained dispersed phase droplets in the continuous phase c) Velocity profile distributions of the continuous phase d) Details concerning the settling trajectories of the dispersed phase Because of this limited information, the common-practice methods are often applied instead of the more theoretical approaches The use of an empirical sizing coefficient, K S O g 4gD P t S S g 3Cd v K where K 10 2

11 6/20/2017 Common-Practice vs Theoretical Methods The theoretical approach requires knowledge of the following variables which are difficult to determine a) Droplet size distributions, which typically change due to shear/coalescence effects Where: b) The amount of entrained dispersed phase droplets vin t = the Terminal velocity continuous phase K 0.5 s = Sizing coefficient 0.5 c) Velocity profile distributions of the continuous phase O g 4gD ρ = Density P vt d) KDetails S concerning the where settling KStrajectories of the dispersed g = Gravitational phase g 3Cd acceleration Because of this limited information, the common-practice D p = Droplet size methods are often applied instead of the more theoretical C d = Drag coefficient approaches The use of an empirical sizing coefficient, K S 11 3

12 6/19/2017 Vertical and Horizontal 2-Phase Separator Vertical Vertical and Horizontal 2-Phase Separator Horizontal Vertical Horizontal 12 1

13 6/19/2017 Vertical and Horizontal 2-Phase Separator Vertical Vertical and Horizontal 2-Phase Separator Horizontal Vertical Horizontal 13 2

14 6/19/2017 Vertical and Horizontal 2-Phase Separator Vertical Flow Pattern Map Bubble, Elongated Bubble Flow Horizontal Flow Horizontal Dispersed Flow Slug Flow Annular Mist Flow Stratified Flow Wave Flow Mandane, et.al. 14 3

15 6/19/2017 Effect of Feed Pipe Velocity on Liquid Entrainment Large Diameter Inlet Pipe Small Diameter Inlet Pipe The horizontal flow patterns and flow pattern map assume that the flow conditions in the feed pipe have reached a well-established, stabilized state This will not be true if the flow has changed direction Vertical runs, elbows, fittings, valves, or other flow pattern disruptions Effect of Feed Pipe Velocity on Liquid Entrainment Large Diameter Inlet Pipe Small Diameter Inlet Pipe Provide 10 diameters of straight pipe upstream of the inlet nozzle without valves, expansions/ contractions, or elbows If a valve in the feed line near the separator is required it should preferably be a full port gate or ball valve Sometimes straightening vanes are used 15 4

16 6/19/2017 Various Separation Equipment Inlet Devices Vane-Type and Cyclonic Inlet Devices Vane-Type Cyclonic-Type 16 5

17 6/19/2017 Comparison of Inlet Devices 17 6

18 6/19/2017 Wire Mesh Mist Extractor in a Vertical Separator Mist extractors (eliminators) are used to remove small droplets from the vapor stream. These droplets are too small to be economically removed in the gravity separation section The primary issues that affect mist extractor selection are: 1) Capacity 2) Separation performance 3) Fouling tendency 4) Turndown performance Mesh Pad Examples Mesh pads are most commonly utilized in vertical separators Typically installed horizontally (vertical gas upflow) Better at removing small droplets Possess a better turndown ratio Have a lower gas handling capacity Are not recommended for dirty/ fouling service Courtesy of ACS Require capacity derating at high pressures Courtesy of Koch-Otto York 18 1

19 6/19/2017 Single and Double Pocket Vane Mist Extractor Vane packs capture droplets primarily by inertial impact and collection in pockets Vanes packs are better suited for dirty/fouling service Have a higher gas handling capacity and able to tolerate higher entrained liquid loads Droplet removal efficiency tends to be lower Require capacity derating at high pressures Vertical Gas Separator Courtesy Koch Glitsch Examples of Demisting Cyclone Configurations 19 2

20 6/19/2017 Examples of Demisting Cyclone Configurations Have the highest gas handling capacity high liquid handling capacity, and excellent droplet removal performance Separation efficiency is insensitive to high pressures Tolerant of entrained solids Most commonly installed in vertical flow orientation Sometimes a wire mesh pad is installed below the cyclones to improve removal efficiency Comparison of Mist Extraction Devices Table (Pg. 24) 20 3

21 6/19/2017 Droplet Settling in Vertical and Horizontal Separators Droplet Settling Relationships The gravity separation section of a separator has two main functions: 1 2 Reduction of entrained liquid load not removed by inlet device, and Improvement or straightening of gas velocity profile In low liquid loading applications, pre-separation of liquid droplets may not be required if the mist extractor can handle the entrainment entering the vessel Droplet Settling in Vertical and Horizontal Separators Droplet Settling Relationships The gravity separation section of a separator has two main functions: 1 2 Reduction of entrained liquid load not removed by inlet device, and Improvement or straightening of gas velocity profile Even in this scenario, a relatively uniform gas velocity distribution should be delivered to the mist extractor to achieve its intended performance 21 1

22 6/19/2017 Droplet Settling in Vertical and Horizontal Separators Droplet Settling Relationships Pre conditing of fluids upstream of mist extractor The gravity separation section of a separator has two main functions: 1 2 Reduction of entrained liquid load not removed by inlet device, and Improvement or straightening of gas velocity profile Droplet Settling in Vertical and Horizontal Separators Droplet Settling Relationships The gravity separation section of a separator has two main functions: 1 2 Reduction of entrained liquid load not removed by inlet device, and Improvement or straightening of gas velocity profile Two approaches for sizing the gravity separation section to remove liquid droplets from the gas: 1 K s method 2 Droplet settling theory 22 2

23 6/19/2017 Droplet Settling in Vertical and Horizontal Separators Droplet Settling Relationships Droplet settling theory Involves sizing the gravity separation section to remove a target liquid droplet size (and all droplets larger than the target size) using the equations presented later in this module The gravity separation section of a separator has two main functions: Two approaches for sizing the gravity separation section to remove liquid droplets from the gas: 1 K s method 2 Droplet settling theory Gravity Separation Section v gmax D min 1 2 Reduction of entrained liquid load not removed by inlet device, and Improvement or straightening of gas velocity profile Vertical vessel sizing: Diameter, D, is based on the maximum allowable gas velocity, v gmax Where: L = liquid density g = gas density v gmax = maximum allowable gas velocity K s = an empirical constant SI FPS kg/m 3 lbm/ft 3 kg/m 3 lbm/ft 3 m/s ft/sec m/s ft/sec 23 3

24 9/13/2018 Gravity Separation Section Vertical vessel sizing: Diameter, D, is based on the maximum allowable gas velocity, v gmax v gmax D min Bulk separation in vessels with no internals For vertical separators, K s may vary from 0.04 to 0.25 m/s [0.13 to 0.82 ft/sec] Variables Affecting K S Vessels equipped with high capacity mist extractors and handling feed stream with small amounts of liquid entrainment In practice, K s values are largely empirical because in addition to mist extractor type and droplet size, K s values also depend on: a. Separator geometry b. Fluid properties c. Velocity profile d. Inlet device design/performance e. Relative amounts of gas and liquid NOTE K S is far more dependent on droplet size than fluid properties. 24 1

25 9/13/2018 K s vs. Pressure and Droplet Size Gravity Separation Section - Vertical Separators 500 Micron Droplets K s vs. Pressure and Droplet Size 300 Micron Droplets 150 Micron Droplets 100 Micron Droplets Gravity Separation Section - Vertical Separators K s values are based on droplet settling considerations only and may require a downward adjustment to account for nonideal conditions. 500 Micron Droplets K s is far more dependent on droplet size than fluid properties. 300 Micron Droplets 150 Micron Droplets 100 Micron Droplets 25 2

26 9/13/2018 K s vs. Pressure and Droplet Size Gravity Separation Section - Vertical Separators For conventional separation applications with a high liquid load, use a value of K s = 0.04 m/s [0.13 ft/sec] 150 microns for medium to high pressure separation Ks = 0.04 m/s K s vs. Pressure and Droplet Size 500 Micron Droplets 300 Micron Droplets 150 Micron Droplets 100 Micron Droplets Gravity Separation Section - Vertical Separators For scrubber applications with a low liquid loading, <56 m 3 /10 6 std m 3 [10 bbl/mmscf], the K s value will depend on the mist extractor type. 500 Micron Droplets Maximum K s value of 0.15 m/s [0.49 ft/sec] recommended for the scrubber diameter. 300 Micron Droplets Ks = 0.13 ft/sec 150 Micron Droplets 100 Micron Droplets 26 3

27 6/19/2017 K s for Horizontal Vessels K s for Horizontal Vessels 3-Phase Separator Internals (Courtesy of KIRK Process Solutions) D L e Foam Breaker L V t V g h g Gas Flow Straightening Device Mist Eliminator Inlet Deflector Submerged Weir Copak Coalescer Vortex Breakers Sand Jetting System Inlet Distribution Baffles Top: Vapor Baffle Bottom: Liquid Baffle 27 1

28 6/19/2017 K s for Horizontal Vessels L L e = L-D D L e V t V g h g K sh = K sv (L e /h g ) V t V g h g It is recommended that K sh be limited to a maximum value of 0.21 m/s or 0.7 ft/sec 3-Phase Separator Internals Foam Breaker Gas Flow Straightening Device Mist Eliminator Inlet Deflector Submerged Weir Copak Coalescer Vortex Breakers Sand Jetting System Inlet Distribution Baffles Top: Vapor Baffle Bottom: Liquid Baffle (Courtesy of KIRK Process Solutions) 28 2

29 6/19/2017 Fractional Area Available for Liquid and Gas Flow Horizontal Separator Figure (Pg. 17) For a vertical separator F g is

30 6/19/2017 Learning Objectives You are now able to: Describe separator applications and common types of separators List the sizing criteria for 2-phase and 3-phase separators Discuss the principles of gas-liquid separation and how they are applied in separator design Describe the effect of inlet piping size and inlet devices on separator sizing List the types of mist extractors and describe typical applications Estimate separator size based on gas-liquid separation criteria 30 1

31 6/20/2017 Learning Objectives Separation Core Emulsions and Oil Dehydration Equipment By By the the end end of of this this lesson lesson, you you will will be able be able to: to: Describe emulsions, how they form and how they influence separator design Discuss how emulsions can be destabilized and eliminated Estimate the size of an oil dehydrator based on liquid-liquid separation criteria 31 1

32 6/20/2017 Emulsions Definition A mixture of two immiscible liquids, one of which is dispersed as droplets (dispersed phase) in another liquid (continuous phase) Two main types: 1. Water in oil (WIO, W/O) also known as a normal emulsion Oil is the continuous phase and water is the dispersed phase 2. Oil in water (OIW, O/W) also known as a reverse emulsion Water is the continuous phase and oil is the dispersed phase Water Phase Emulsifying compound Water-in-Oil Oil Phase Oil-in-Water Oil Phase Water Phase Emulsifying compound From a practical standpoint, WIO emulsions are more frequently encountered in production operations and more difficult to resolve than OIW emulsions Water in Oil and Problems Cause by Emulsions Oil must meet a water content (or BS&W) specification before it can be transported or sold Typical BS&W specifications range from 0.3 to 3% by volume Water entrained in oil increases transportation costs Water entrained in oil can cause corrosion in pipelines and associated equipment If the entrained water has a high salinity, a lower BS&W specification may be required to meet the salt specification Problems cause by emulsions Emulsions make the dehydration of crude oil and the deoiling of produced water more difficult because: Dispersed droplets do not coalesce and separate from the continuous phase The viscosity of the emulsion can be much higher than the viscosity of the continuous phase 32 2

33 6/20/2017 Conditions Required to Form Emulsions There are three requirements for forming an emulsion: Two immiscible liquids (oil and water) Agitation to disperse one liquid as droplets in the other Compounds which stabilize the emulsion thereby inhibiting coalescence and increasing the time required for separation When we use the word stable in talking about emulsions we mean how difficult is it to separate the two phases Example of Normal Emulsion Water-in-oil (normal) emulsion: OIL 33 3

34 6/20/2017 Example of Normal Emulsion Water-in-oil (normal) emulsion: OIL Some Common Household Emulsions Salad Dressing Type: generally oil in water Emulsifying compound: mustard 34 4

35 6/20/2017 Some Common Household Emulsions Salad Dressing Type: generally oil in water Emulsifying compound: mustard Mayonnaise Type: oil in water Emulsifying compound: egg yolk lecithin or egg white proteins Some Common Household Emulsions Salad Dressing Type: generally oil in water Emulsifying compound: mustard Mayonnaise Type: oil in water Emulsifying compound: egg yolk lecithin or egg white proteins Homogenized milk Type: oil in water Emulsifying compound: proteins in the milk 35 5

36 6/20/2017 Some Common Household Emulsions Salad Dressing Type: generally oil in water Emulsifying compound: mustard Mayonnaise Type: oil in water Emulsifying compound: egg yolk lecithin or egg white proteins Homogenized milk Type: oil in water Emulsifying compound: proteins in the milk Butter or Margarine Type: water in oil Emulsifying compound: proteins in the cream Some Common Household Emulsions Salad Dressing Type: generally oil in water Emulsifying compound: mustard Mayonnaise Type: oil in water Emulsifying compound: egg yolk lecithin or egg white proteins Homogenized milk Type: oil in water Emulsifying compound: proteins in the milk Butter or Margarine Type: water in oil Emulsifying compound: proteins in the cream Latex Paint Type: oil in water Emulsifying compound: various surfactants 36 6

37 6/20/2017 Sources of Agitation Bottomhole pumps Flow through tubing, wellheads, chokes, flowlines, production manifolds Ineffective or poorly designed separator inlet devices Process pumps, control valves, flow through process piping Emulsifying Compounds A surface-active compound that alters the characteristics of the oil-water interface There is normally no shortage of emulsifying agents present! 37 7

38 6/20/2017 Emulsifying Compounds A surface-active compound that alters the characteristics of the oil-water interface Migrates to the oil-water interface and concentrates there Forms a barrier that prevents droplets from coalescing Lowers system interfacial tension (IFT) allowing formation of smaller droplet sizes Types of emulsifying compounds 1. Indigenous surface active compounds (surfactants) Asphaltenes, resins, naphthenic acids, etc 2. Finely divided solids Formation fines, e.g., sand, silt, clay Drilling muds/workover fluids Mineral scales, corrosion products, wax 3. Added chemicals Corrosion inhibitors, paraffin dispersants, stimulation chemicals, etc. There is normally no shortage of emulsifying agents present! Rigid Film Surrounding Water Droplets in WIO Emulsion An emulsifying agent forms a viscous barrier that inhibits droplet coalescence Emulsifying agents surround the water droplet and form a skin 38 8

39 6/20/2017 Typical Emulsion Droplet Size Distributions Distribution Function Droplet Diameter (microns) Tight (Difficult) Small droplets More stable Modelling Oil-Water Separation FPS SI v t, terminal settling velocity ft/sec m/s g, gravitational acceleration 32.2 ft/sec m/s 2 D p, droplet diameter ft m ρ w, water density lb/ft 3 kg/m 3 ρ o, oil density lb/ft 3 kg/m 3 µ o, oil viscosity lb/ft-sec kg/m-s Note: 1cP = kg/m s = 6.72x10-4 lbm/ft-sec Loose (Easier) Larger droplets Less stable Design of oil dehydration equipment is complex and is very much based on experimental data v t gd 2 p ( w 18 ) o o 39 9

40 6/20/2017 Modelling Oil-Water Separation Droplet size, D p Droplet sized is the most important parameter in oil-water separation Doubling the droplet size increases the settling velocity by a factor of 4 Larger droplet sizes are achieved by: Reducing shear in the production system Increasing the interfacial tension Modifying the effect of the emulsifying agent Using separator internals that promote coalescence Oil viscosity, µ o Oil viscosity is the second most important parameter in oil-water separation Halving the oil viscosity increases settling velocity by a factor of 2 Lower oil viscosity is achieved by: Increasing separation temperature Density difference, ρ w ρ o The density difference between oil and water is the third most important parameter in oil-water separation Typically we have little control over the fluid densities although increasing the temperature may have a small effect on the density difference 40 10

41 6/21/2017 Three Main Steps Destabilization Weaken the film surrounding the small water droplets Flocculation/ Coalescence Get the small droplets to collide, coalesce, and grow into larger droplets What equipment or means do we use to accomplish the above? Heat Heat Benefits of heating: Reduces oil viscosity Chemical demulsifiers Mechanical devices to promote coalescence Electricity to promote coalescence Retention time/cross sectional area Gravity Separation/ Sedimentation Allow time for the coalesced water droplets to settle out of the oil due to density difference Increases movement of droplets due to convection currents which aids coalescence Destabilizes the interfacial film/skin around the droplets Increases solubility of waxes and asphaltenes (emulsifying agents) May increase the density difference Disadvantages of heating: Oil shrinkage due to loss of light components Reduction of API gravity Increased water solubility in oil Scale deposition Fuel cost 41 1

42 6/21/2017 Example Oil Dehydration Temperatures Emulsion Type o API Gun Barrels Wash Tanks ºF (ºC) Loose > (27 38) Moderate (38 49) Tight (49 +) Very viscous (66 +) Heater Treaters ºF (ºC) (38 49) (49 82) (60 82) (82 121) Electrostati c TreaterºF (ºC) (29 41) (41 60) (49 71) (71 110) Use of electricity can reduce required temperature and heat input Chemical Demulsifiers What are they? A wide range of surface active chemicals used to destabilize oilfield emulsions and promote solids removal WIO demulsifiers are highly oil soluble OIW (reverse) demulsifiers are highly water soluble What do they do? 1. Strong attraction to the oil/water interface 2. Deactivate emulsifying agents by dissolving them in one of the phases 3. Promote flocculation and coalescence by weakening the film around the water droplet 4. Solids wetting remove solids from the oil-water interface by making them migrate to the water phase, e.g. iron sulfide and reservoir fines or making them migrate to the oil phase, e.g. paraffins and asphaltenes 42 2

43 6/21/2017 Demulsifiers Without Demulsifiers With Demulsifiers Emulsion Breaker Demulsifiers Without Demulsifiers With Demulsifiers Emulsion Breaker = EB Emulsion Breaker Without demulsifier treatment, the film around the water droplet remains intact With demulsifier treatment, the emulsifying agents are into one of the two phases (usually the continuous phase) Without demulsifier treatment, the pliable film around the water droplet remains intact when a collision occurs With demulsifier treatment, the film becomes brittle and ruptures when a collision occurs 43 3

44 6/21/2017 Demulsifiers Without Demulsifiers With Demulsifiers Emulsion Breaker = EB Emulsion Breaker Without demulsifier treatment, the film around the water droplet remains intact Demulsifiers Without Demulsifiers With Demulsifiers With demulsifier treatment, the emulsifying agents are into one of the two phases (usually the continuous phase) Without demulsifier treatment, the pliable film around the water droplet remains intact when a collision occurs With demulsifier treatment, the film becomes brittle and ruptures when a collision occurs Emulsion Breaker Without demulsifier treatment, the film around the water droplet remains intact With demulsifier treatment, the emulsifying agents are into one of the two phases (usually the continuous phase) Without demulsifier treatment, the pliable film around the water droplet remains intact when a collision occurs With demulsifier treatment, the film becomes brittle and ruptures when a collision occurs 44 4

45 6/21/2017 Demulsifiers Without Demulsifiers With Demulsifiers Emulsion Breaker = EB Emulsion Breaker Without demulsifier treatment, the film around the water droplet remains intact Chemical Demulsifiers Selection With demulsifier treatment, the emulsifying agents are into one of the two phases (usually the continuous phase) Without demulsifier treatment, the pliable film around the water droplet remains intact when a collision occurs With demulsifier treatment, the film becomes brittle and ruptures when a collision occurs Different demulsifier compounds have different properties Water drop: effective at coalescing water droplets Dehydration: flocculate submicron water droplets Wetting agents: interact with solids to change wettability of their surfaces Interface quality and water clarity Normally screened/selected based on bottle tests Typically use a tailored blend of chemicals to achieve the desired performance Electrostatic bench tests Chemical effectiveness can be different in the presence of an electric field Concentrations of ppm are typical (overdosing can make emulsions worse) Injection point What type of emulsion is to be treated What is the water cut What is the temperature range and can the system be heated Is the feed composition constant or variable 45 5

46 6/21/2017 Internals to Promote Droplet Coalescence Internals designed to promote coalescence of dispersed phase droplets are sometimes installed in the liquid holding sections of three-phase separators Coalescing Plate Pack (Courtesy Koch Glitsch) Internals to Promote Droplet Coalescence v t gd 2 p ( Natco Horizontal PERFORMAX Treater Coalescing Matrix Plates Internals designed to promote coalescence of dispersed phase droplets are sometimes installed in the liquid holding sections of three-phase separators Stokes Law w 18 ) o o 46 6

47 6/21/2017 Electricity to Promote Droplet Coalescence Electrostatic treaters (coalescers) apply a high voltage electric field to an emulsion to enhance separation Two main types: Alternating current (AC) Alternating/direct current (AC/DC) Voltage modulation Dual frequency Typical voltage levels: 12,000 30,000 V How does it work? Electricity to Promote Droplet Coalescence Ratio of electrostatic to gravity forces is ~ 1,000 for 4 microns diameter water drops in 20 o API crude 47 7

48 7/20/2017 Free Water Knockout (FWKO) Long residence time (2-20 min) May include a gas boot if gas bubbles interfere with separation efficiency Pressure about 50 psig (350 kpag) or lower Can be horizontal or vertical Free Water Knockout (FWKO) 48 1

49 7/20/2017 Gunbarrel or Wash Tank Gunbarrel or Wash Tank API 421 Recommends short circuiting factor of 1.75, so For a retention time of 8 hours, design for 49 2

50 7/20/2017 Gunbarrel or Wash Tank Cutaway of a Vertical Heater Treater 1. Emulsion in at top 2. Gas leaves from top 3. Drop to FWKO section 4. Oil (lighter fluid) moves upward through perforated baffles 5. Hot dehydrated oil out heat exchange with emulsion feed 6. Water leaving the bottom of the treater through the dump valve 7. Maximum capacity typically 10,000 Bbls/day [1590 m3/h] 8. Very common onshore mature field Direct Fired 50 3

51 7/20/2017 Cutaway of a Horizontal Heater Treater Gas Gas Dehydrated Oil Coalescing section Electrostatic Treater Free Water Separated Water Courtesy Natco 51 4

52 7/20/2017 Typical Liquid Residence Times Type of Treater Gun Barrels or Wash Tanks (Settles via Stokes Law) Vertical Heater Treaters Horizontal Heater Treaters Electrostatic Treaters Typical Liquid Phase Residence Time 8 24 hr Heavy crudes or low volume hr hr 5 min 0.75 hr Offshore and heavy crudes 52 5

53 Oil-Water Separation Well fluid production facilities and in the gas conditioning and processing facilities, such as hydrocarbon dew point control plant, we encounter separation of oil, water and gas phases Similar to degassing of a liquid phase, two methods are used to size the liquid-liquid separation section: Residence Time Method Droplet Settling Theory Horizontal 3-Phase Separator 53

54 Water-in-Oil and Oil-in-Water Separation Criteria P 34 Three-Phase Separator Configurations Gas-oil and Oil-water level control arrangements for 3-phase separators Overflow Weir Submerged Weir The Bucket and Weir Submerged Weir with Boot 54

55 Three-Phase Separator Configurations Gas-oil contact is fixed by the weir, so no liquid level control is required It is more difficult to adjust the gas-oil interface to compensate for changing gas-liquid requirements Any slugs/surges entering the separator may spill over into the oil compartment For viscous oils, there is increased possibility of entrainment of gas into the oil due to the waterfall effect Three-Phase Separator Configurations Requires level control at gas-oil interface but allows more flexibility Better able to accommodate slugs & surges Allows for more stable oil flow out of separator Ability to adjust oil-water interface may be limited due to shorter weir height Overflow Weir Submerged Weir 55

56 Three-Phase Separator Configurations Bucket and Weir design is sometimes favored in smaller separators because it does not require interface level control Disadvantages include: Increased complexity Limited retention time in the oil and water compartments Limited flexibility to adjust levels as water cuts and GOR change over the field life Bucket and Weir 56

57 6/19/2017 Learning Objectives You are now able to: Describe emulsions, how they form and how they influence separator design Discuss how emulsions can be destabilized and eliminated Estimate oil dehydrator size based on liquid-liquid separation criteria PetroAcademy TM Gas Conditioning and Processing Core Hydrocarbon Components and Physical Properties Core Introduction to Production and Gas Processing Facilities Core Qualitative Phase Behavior and Vapor Liquid Equilibrium Core Water / Hydrocarbon Phase Behavior Core Thermodynamics and Application of Energy Balances Core Fluid Flow Core Relief and Flare Systems Core Separation Core Heat Transfer Equipment Overview Core Pumps and Compressors Overview Core Refrigeration, NGL Extraction and Fractionation Core Contaminant Removal Gas Dehydration Core Contaminant Removal Acid Gas and Mercury Removal Core 57 1