Surface Operations And Storage

Separation

Gas Liquid Separation

Mauricio Prado – The University of Tulsa

1

Introduction

• Mother nature spends millions of years separating the oil/water in the reservoir. Production engineers spend minutes mixing it up in the well bore which forces facility engineers to spend countless hours and dollars designing and building equipment to separate the phases all over again. • Well produced fluids are a complex mixture of different hydrocarbons components with different densities, vapor pressures and other physical properties

Mauricio Prado – The University of Tulsa

2

Introduction

• Depending on the mixture composition and the pressure and temperature, the mixture can present in the following states – Single phase liquid – Single phase gas – Gas – liquid mixture

• The physical separation of the gas-liquid mixture is one of the basic operations of the processing of produced fluids

Mauricio Prado – The University of Tulsa

3

Introduction

• The oil-gas separator, mechanically separates the streams of liquid and gas at a certain pressure and temperature • It is usually the first initial processing vessel in a treatment facility • Separators must be properly designed. Poor performance can reduce the capacity of the entire facility since downstream vessels and equipment will be affected by the quality of the separated streams coming from the separator. • All separators are sized in accordance to the same principles and procedures Mauricio Prado – The University of Tulsa

4

Separators Classification

• Number of phases separated – Two Phase Separators • Separates gas from the total liquid (usually used for the first separation stages)

– Three Phase Separators • Separates gas, oil and water (usually used in the last separation stage)

• Construction type – – – – –

Horizontal Vertical Spherical Cyclonic Horizontal Double barrel

Mauricio Prado – The University of Tulsa

5

Separators Classification

• Usage – Production separator • Field vessels used to separate gas, oil and water coming directly from an oil or gas well, or group of wells

– Flash Chamber • This is a vessel used as a subsequent stage of separation to process the liquid hydrocarbons flashed from a primary separator • The vessel is usually of low-pressure design (<125 psig)

– Test separator • Field vessels used to separate gas, oil and water coming directly from an oil or gas well being tested so that individual fluid production from the well can be measured

– Gas Scrubber (high gas to liquid ratio) • Vessel normally more efficient than conventional separators in removing small liquid drops from a gas phase

– Gas Filter (Dust scrubber or coalescer) • Designed to remove small quantities of mist, oil fogs, rust, scales, and dust from gases. Normally upstream of compressors, dehydration units, amine units, LACT custody transfer units

– Expansion Vessel (cold separator or a low-temperature separator) • The vessel into which gas is expanded for a cold separation application • The vessel differs considerably from the normal separator because it is designed primary to handle and melt gas hydrates that are formed by expansion cooling • The working pressure if this vessel is in the range of 1000-1500 psig Mauricio Prado – The University of Tulsa

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Separators

• Separator sections – – – –

Primary separation section Liquid accumulation section Gravity settling section Mist extraction or coalescence section

Mauricio Prado – The University of Tulsa

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Primary Separation Section

• Area for collection and removing the bulk of the liquid in the inlet stream • Inlet baffling is usually used to exploit the momentum of the inlet stream either by centrifugal force or an abrupt change of direction thus separation most of the liquid

Mauricio Prado – The University of Tulsa

8

Liquid Accumulation Section

• Section that collects the liquids removed from the gas and provides sufficient capacity to handle surges in liquid flows and to allow gas entrained to be separated from the liquid

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9

Secondary or Gravity Settling Section

• Gas velocity and turbulence is reduced so that entrained liquid crops can settle out by gravity

Mauricio Prado – The University of Tulsa

10

Mist Extraction or Coalescence Section

• Consist of a series of vanes, a woven wire mesh pad, or centrifugal device, removes small droplets from the gas stream • Liquid carry-over often meets a 0.1 gallon per MMscf

Mauricio Prado – The University of Tulsa

11

Horizontal Separators

• Fluid enters the separator and hits an inlet diverter (momentum absorber) causing a change in the flow direction • Some gross initial separation occurs at the diverter and gravity causes the liquid phase to drop to the bottom of the vessel where it is collected. Part of the gas accumulates in the top portion of the separator

Mauricio Prado – The University of Tulsa

12

Horizontal Separators

• The liquid accumulation section allows a certain retention time required to let entrained gas bubbles in the liquid to rise to the upper vapor space. It also provides a “surge space” to accommodate for eventual liquid slugs in the production

Mauricio Prado – The University of Tulsa

13

Horizontal Separators

• A similar process occur in the vapor section, where liquid droplets entrained in the liquid fall to the gas liquid interface • Small liquid droplets that can not be separated by gravity are coalesced in meshes or plates in the mist extractor • In the case of foams a defoaming element can be used to break the foam

Mauricio Prado – The University of Tulsa

14

Horizontal Separators

Mauricio Prado – The University of Tulsa

15

Horizontal Separators

• The liquid dump valve is regulated by a level controller. • The level controller senses changes in the liquid level and actuates the valve. • The pressure in the separator is maintained by a pressure controller • The pressure controller senses the pressure inside the separator and send signals to the pressure control valve to open or close controlling the amount of gas that leaves the vapor space

Mauricio Prado – The University of Tulsa

16

Vertical Separators

Mauricio Prado – The University of Tulsa

17

Vertical Separators

• Fluid enters the separator from the side • A diverter causes an initial separation • Liquid falls down to the liquid collection section. • Liquid continues to flow to the liquid outlet • Gas bubble rise through the liquid column joining the initial separated gas in the vapor chamber. • Liquid droplets in the vapor chamber drop towards the gas-liquid interface • Gas goes through a demister before exiting the vessel • Liquid level and pressure are controlled the same way as in a horizontal separator.

Mauricio Prado – The University of Tulsa

18

Vertical Separators

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Spherical Separators

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Spherical Separators

• Exactly the same as a vertical separator without the cylindrical part connecting the two hemispheres • Very good in containing high pressure • Difficult to construct • Limited capacity to absorb liquid surges

Mauricio Prado – The University of Tulsa

21

Cyclone Separators

• Designed to operate by centrifugal forces • The swirling action separates the liquid from the gas

Mauricio Prado – The University of Tulsa

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Cyclone Separators

• Very small in size • Design is very sensitive to flowrate • High demand in recent years for offshore operation due to their reduced size

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Horizontal Two Barrel Separators

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Horizontal Two Barrel Separators

• Commonly used for very low liquid flowrates • Gas and liquid chambers are separated • The liquid chamber is separated from the gas chamber to prevent liquid to be re-entrained by high gas velocities.

Mauricio Prado – The University of Tulsa

25

Horizontal Two Barrel Separators

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Horizontal Two Barrel Separators

• For some high gas to liquid ratio applications the two barrel separator can be equipped with filter tubes to cause coalescence of the liquid droplets

Mauricio Prado – The University of Tulsa

27

Comparison of Horizontal and Vertical Separators

• Horizontal separators – Advantages • Smaller diameter than vertical separators for the same capacity • Liquid droplets fall perpendicular to the gas main flow direction and are then easier to separate from the gas phase • The bigger gas-liquid interface also improves the separation of entrained gas in the liquid • The bigger gas-liquid interface also helps with foam • They have higher liquid capacity than vertical ones • Cheaper than vertical separators • Can be mounted in skids and be easily transported

Mauricio Prado – The University of Tulsa

28

Comparison of Horizontal and Vertical Separators

• Horizontal separators – Disadvantages • Not good in handling solids since solids can build up in the liquid accumulation area. In a vertical separator the liquid outlet can be located at the center of the bottom head and solids can continue to the next process vessel with the liquid • Require more footprint area than vertical separators which is a important issue in offshore production • Although having a higher liquid capacity than vertical separators, they have a poor performance in absorbing surges – Due to the small vertical distance between the inlet and outlet pipes, the high-level shut-down device is located very close to the normal operating level. In a vertical separator the high level sensor can be in a much higher position in relation to the normal liquid level, thus having a higher capacity to absorb surges – Surges can also cause waves in the liquid level that will trigger the high-level control

• Liquid level control for the reasons above is more critical • Difficult to clean sand and solids deposited at the bottom

Mauricio Prado – The University of Tulsa

29

Comparison of Horizontal and Vertical Separators

• Horizontal separators – Normal uses • • • •

Large volumes of gas or liquid High to medium GLR Foaming oil Ideal for three-phase separation

Mauricio Prado – The University of Tulsa

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Comparison of Horizontal and Vertical Separators

• Vertical separators – Advantages • More versatile than horizontal • Adequate for test separator • Liquid level control is not so critical. Due to the distance between inlets and outlets the high-level sensor can be located higher than the normal operating level • Easy to clean sand, hydrates, paraffin that deposits on the bottom • Smaller foot print

Mauricio Prado – The University of Tulsa

31

Comparison of Horizontal and Vertical Separators

• Vertical separators – Disadvantages • • • •

More expensive than horizontal separators Large diameter for high gas capacities Most competitive for very low or very high GLR More difficult to mount, ship and service control and safety devices

Mauricio Prado – The University of Tulsa

32

Comparison of Horizontal and Vertical Separators

• Vertical separators – Normal uses • Sand, paraffin, or other solid are produced • Space is limited • Ease of level control is desired • Small flow rates • very low or very high (i.e., scrubber) GLR

Mauricio Prado – The University of Tulsa

33

Separator Equipment

• Separator Internals – – – – –

Inlet diverters Wave breakers Defoaming plates Vortex breaker Mist extractor

• Other equipment – Process control – Safety devices

Mauricio Prado – The University of Tulsa

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Separator Internals

• Inlet diverters – Baffle plates • Can be a spherical dish, flat plate, cone that will force the stream to quickly change flow direction enabling the separation of gas and liquid due to their different densities

– Centrifugal diverters • Uses centrifugal forces to separate liquid and gas.

Mauricio Prado – The University of Tulsa

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Separator Internals

• Inlet diverters – Baffle plates

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Separator Internals

• Inlet diverters – Centrifugal

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Separator Internals

• Wave Breakers – Used in horizontal vessels. Vertical baffles that spans the gas-liquid interface preventing waves from traveling along the vessel

Mauricio Prado – The University of Tulsa

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Separator Internals

• Defoaming plates – Foam can occurs when gas liberates from the liquid. – The foam can be removed by forcing the fluids to flow through parallel plates or tubes helping the coalescence of the foam bubbles

Mauricio Prado – The University of Tulsa

39

Separator Internals

• Vortex breaker – Prevent the formation of vortex when the liquid control valve is open

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Separator Internals

• Mist extractor – – – –

Wire mesh Vanes Centrifugal devices Packing

Mauricio Prado – The University of Tulsa

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Separator Internals

• Mist extractor – Wire mesh • Liquid droplets impinge the wires and coalesce. Work on a certain gas velocity range. Too low velocity the droplets do not coalesce. Too high velocity the gas can re-entrain the coalesced droplets • Used only when plugging by solids is unlikely

Mauricio Prado – The University of Tulsa

42

Separator Internals

• Mist extractor – Vanes • Forces the gas to flow in laminar regime between parallel channels with directional changes. Liquid droplets impinge the walls of the channel, coalesce and drop into the liquid collection area

Mauricio Prado – The University of Tulsa

43

Separator Internals

• Mist extractor – Centrifugal • • • •

Centrifugal forces cause the liquid to be separated Very efficient and less susceptible to plugging Very sensitive to flow rate variation Large pressure drop through the device

Mauricio Prado – The University of Tulsa

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Separator Internals

• Mist extractor – Packing • Random packing can also be used as a coalescer for mist extraction

Mauricio Prado – The University of Tulsa

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Process Control

• Process Controls – Separator pressure is generally controlled by a backpressure regulator in the exit gas line – Separator temperature is usually not controlled except for heater-treaters – Liquid level contoller • Two-Phase separators have one liquid level controller for the liquid accumulation section • Three-Phase units have two liquid level controllers to regulate the release of crude and water • Types – Open separator – Weir plate – Bucket and weir plate

Mauricio Prado – The University of Tulsa

46

Process Control

• Open separator – Simple and inexpensive approach – Uses a float displacement sensor with no baffles or weirs – Advantages: • Relative retention volumes can be varied easily • No traps to accumulate sand • Easy to clean separator

– Disadvantages: • Failure of water level controller results in entire liquid stream being discharged through water outlet • Oil-water interface hard to measure • Small drop in the oil level will results in gas entering the oil outlet

Mauricio Prado – The University of Tulsa

47

Process Control

• Weir plate – Advantages: • Interfacial (oil-water level) control is easier to operate • Relative retention times can be varied easily • The cleanest oil is taken off the top

– Disadvantages: • Use of baffle makes removal of sand and mud difficult • Dead space in vessel because oil-water separation stops when the oil flows over the weir • The interface level controller must sense the difference in densities of the oil and water

Mauricio Prado – The University of Tulsa

48

Process Control

• Bucket and weir plate – Advantages: • Only float level control is used; controllers sense the large density difference between liquid and gas • If level control or valves fail, only that liquid and gas are discharged

– Disadvantages: • • • •

More internal baffles are required Difficult to remove sand and mud More vessel space is wasted More difficult to vary the relative liquid retention volumes (i.e., adjusting the bucket and weir is difficult)

Mauricio Prado – The University of Tulsa

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Process Control

• Safety Device – ASME Boiler and Pressure Vessel Code requires that all separators be protected by pressure relief devices such as relief valves and/or rupture disks

Mauricio Prado – The University of Tulsa

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Operational Problems

• Operational problems – – – –

Foamy crudes Paraffin Sand Liquid carryover and gas blow-by

Mauricio Prado – The University of Tulsa

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Operational Problems

• Foamy crudes – Adequate time and sufficient coalescing surface must be provide to break the foam – Foam problems • Difficult level control since the control device must deal with 3 phases instead of two • Foam can occupy large space in the liquid accumulation section or gravity settling section • If the foam is not controlled we may have gas in the oil outlet or liquid in the gas outlet

– Temperature may significantly affect foam tendency – Foam depressants although expensive are successful in inhibiting foam formation

Mauricio Prado – The University of Tulsa

52

Operational Problems

• Paraffin – Can cause plugging in coalescence plates, mesh and mist extractors – Plate type coalescence and centrifugal extractors are better when paraffin may be a problem – Temperature should always be above cloud point of the crude

Mauricio Prado – The University of Tulsa

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Operational Problems

• Sand – Can cause erosion problems – Accumulates in the bottom of the separator – Plugging of internal elements

Mauricio Prado – The University of Tulsa

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Operational Problems

• Liquid carry-over – Occurs when free liquid escapes with the gas phase. • Causes – – – – – –

High liquid level Damage to internals Foam Bad design Plugged liquid outlets Excessive gas flowrate

Mauricio Prado – The University of Tulsa

55

Operational Problems

• Gas blow-by – Occurs when free gas escapes with the liquid phase • Causes – Low liquid level – Vortexing – Level control failure

Mauricio Prado – The University of Tulsa

56

Factors Affecting Separation

• Gas and liquid flow rates (minimum, average, and peak) • Operating and design pressures and temperatures • Surging or slugging tendencies of the feed streams • Physical properties of the fluids such as density, viscosity and compressibility

Mauricio Prado – The University of Tulsa

57

Factors Affecting Separation…

• Designed degree of separation (e.g. removing 100% of particles greater than 10 microns) • Presence of impurities (paraffin, sand, scale, etc.) • Foaming tendencies of the crude oil • Corrosive tendencies of the liquids or gas

Mauricio Prado – The University of Tulsa

58

Sizing of Separators

• Theory – Two phenomena must be understood in order to size separators • Droplet settling – In the gravity settling section, liquid drops will settle at a velocity determined by the balance of gravitational force and gas drag

• Retention time – Liquid and gas must be stored in the separator for a certain time to achieve equilibrium. This also allows time for gas bubbles dispersed in the liquid in the liquid accumulation section to come to the interface and be separated

Mauricio Prado – The University of Tulsa

59

Droplet Settling

• The movement of a droplet of liquid in the gas is given by a force balance • Lets imagine a droplet with a certain diameter d and a certain cross section area A

Fd Droplet terminal settling velocity

Drag force

d

Buoyancy force

Fb Vt Fg

Mauricio Prado – The University of Tulsa

Gravitational force

d2 A 4

60

Terminal settling velocity

• The drag force is given by:

Vt 2 Fd  Cd A g 2

micron

poundal

ft/s

Fd  4.2266 10 12 Cd d 2  gVt 2 Drag coefficient

Mauricio Prado – The University of Tulsa

lb/ft3

61

Terminal settling velocity

• The drag coefficient is given by:

Cd 

24 3   0.34 Re Re

micron

Re  4.88 10

3

ft/s lb/ft3

dVt  g

g cp

Mauricio Prado – The University of Tulsa

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Terminal settling velocity

• The gravitational force and the buoyancy forces are:

lb/ft3

poundal

Fg   l g

 d3

Fg  5.95 10 6  l d 3

6

micron

lb/ft3

poundal

Fb   g g

 d3 6

Fb  5.95 10 6  g d 3 micron

Mauricio Prado – The University of Tulsa

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Terminal settling velocity

• The force balance becomes Fd  Fg  Fb

4.2266 10 12 Cd d 2  gVt 2  5.95 10 6 d 3  l   g 

micron

lb/ft3

ft/s

d Vt  0.0119 Cd

Mauricio Prado – The University of Tulsa

 l   g    g 

   

64

Terminal settling velocity

• The solution is iterative

micron

Re  4.88 10

3

ft/s lb/ft3

dVt  g

Cd 

g

24 3   0.34 Re Re

cp micron

lb/ft3

ft/s

d Vt  0.0119 Cd

Mauricio Prado – The University of Tulsa

 l   g    g 

    65

Terminal settling velocity

• The terminal settling velocity is essential to design separators • The terminal settling velocity allows us to calculate the time that it takes for a droplet to leave the upper part of the vapor area and reach the liquid interface. • The main idea is that the gas residence time (time that the gas stays inside the separator) must be equal or greater than the time required for the droplets to reach the liquid interface • This depends on: – Vessel construction and size (distance between the droplet and interface) – Gas and liquid properties (densities and gas viscosity) – Gas flowrate – Droplet size

• We can see then that for a certain construction type, gas flowrate and fluid properties we can calculate the size to separate droplets of a certain size Mauricio Prado – The University of Tulsa

66

Drop Size

• The purpose of the gas separation section is to remove most of the bigger droplets from the gas so that the mist extractor needs only to extract the very small droplets. • From field experience it seems that the best separator designs are done when the gas separation section removes liquid drops greater than 100 micron. In this condition, the mist extractor will not be flooded with big drops and will be able to remove drops between 10 and 100 micron • In some cases we can design separators to remove bigger particles (for instance 500 micron) as in the case of the design of gas scrubbers • Flare or vent scrubbers can also be designed for the 300 -500 micron range. In those cases the gas is directly discharge to the atmosphere and a mist extractor should not be used since it may get plugged creating a safety hazard. If a mist extractor is used, safety relief devices should be used in case it gets plugged Mauricio Prado – The University of Tulsa

67

Retention Time

• Retention time Is defined as the average time a molecule of liquid is retained inside the separator. • The retention time is then the volume of the separator divided by the liquid flowrate • Usually 30 seconds to 3 minutes is the normal retention time interval. • In case of foamy oils this may be increased by a factor of 4. • API Specification 12J (1989) recommends for cases that do not have foaming, waxing and slugging the following liquid retention times Crude API

Retention Time (min)

>35

1

20 - 30

1-2

10 - 20

2-4

Liquid Storage Volume tr  ql Mauricio Prado – The University of Tulsa

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Re-entrainment

• Re-entrainment is a phenomenon caused by high gas flowrates disturbing the gas-liquid interface creating turbulence and waves that can remove liquid droplets and re-entrain them in the gas section • In general re-entrainment is minimized if the ratio of the separator length to the separator diameter is smaller than 5 for horizontal separators

Mauricio Prado – The University of Tulsa

69

Horizontal Separator Sizing

• Must determine – Separator length – Separator diameter

• Must satisfy – For a design gas capacity the separator must be able to remove liquid drops greater than a certain size – Provide sufficient residence time for the gas and liquid to reach equilibrium – Prevent re-entrainment

• Usual Assumptions – Separator is 50% full of liquids – Minimum drop size to be separate 100 micron

Mauricio Prado – The University of Tulsa

70

Horizontal Separator Sizing

• Gas capacity – The gas residence time must be equal to the time required for a droplet to reach the gas liquid interface

Vg qg

Mauricio Prado – The University of Tulsa

Vt

71

Horizontal Separator Sizing

• Gas capacity – Gas residence time Separator effective length Gas flowrate

Gas residence time

tg 

Leff

Vg 

Vg

qg

Temperature

Separator diameter

Ag  1  f 

Ag

Gas velocity

q g  q gsc

Fraction of separator filled with liquid

d s2 4

Gas flow area

Compressibility factor

T  460 14.7 Z 520 P Pressure

Gas flowrate standard conditions

Mauricio Prado – The University of Tulsa

72

Horizontal Separator Sizing

• Gas capacity – Gas residence time

s

fraction

ft

in

Leff

psia

P t g  16669 1  f  sc d T  460Z qg scf/d

Mauricio Prado – The University of Tulsa

2 s

F

73

Horizontal Separator Sizing

• Gas capacity – Time for the droplet to reach the interface

Time for drop to reach interface

Separator diameter

ds t d  (1  f ) Vt Droplet terminal settling velocity

Mauricio Prado – The University of Tulsa

74

Horizontal Separator Sizing

• Gas capacity – Time for the droplet to reach the interface

in

fraction

s

td  7

d s (1  f ) d Cd

micron

Mauricio Prado – The University of Tulsa

 l   g    g 

    lb/ft3

75

Horizontal Separator Sizing

• Gas capacity sizing

ft

F

scf/d

in

Leff d s  0.00042 d Cd micron

Mauricio Prado – The University of Tulsa

T  460Z

q gsc  l   g    g 

   

P psia

lb/ft3

76

Horizontal Separator Sizing

• In situ properties

lbm/ ft3 lbm/ ft3

141.5  131.5  API

 l  62.4 

ft3/ scf

lbm/ ft3

141.5  l  62.4 131.5  API

deg F psia

lbm/ ft3

g 

0.0764  g

Bg  0.028269

Bg ft3/scf

(T  460) Z P  14.7 

 g  2. 7

 gP (T  460) Z

psig

F

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Horizontal Separator Sizing

• Gas capacity sizing

ft

F

scf/d

in

Leff d s  0.00042 d Cd micron

Mauricio Prado – The University of Tulsa

T  460Z

q gsc  l   g    g 

   

P psia

lb/ft3

78

Horizontal Separator Sizing

• Liquid capacity – The liquid capacity is calculated by setting the minimum liquid residence time

ql

Vl

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Horizontal Separator Sizing

• Liquid capacity – Liquid retention time Liquid residence time

Separator diameter

Liquid volume

tl 

V ql

V f

d s2 4

Leff

Liquid flowrate

ft

in

bpd

Leff d s2 

Mauricio Prado – The University of Tulsa

min

0.7149 tl ql f

80

Horizontal Separator Sizing

• Seam to Seam Length – After the effective separator length is calculate we provide necessary space for the inlet diverter and mist extractor.

ft

ft

in

d Lss  Leff  12 For gas capacity

Mauricio Prado – The University of Tulsa

Lss 

4 Leff 3

For liquid capacity

81

Horizontal Separator Sizing

• Slenderness ratio – Experience shows that slenderness ratio should be no greater than 5. – Usual values are around 3 to 4

ft

12 Lss sr  d in

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82

Horizontal Separator Sizing

• Determine gas flowrate, gas density, gas viscosity, liquid flowrate and API • Determine operating temperature and pressure • Determine the liquid retention time • Calculate in-situ properties • Determine the minimum drop size to be separated • Calculate drop terminal settling velocity • For several diameters – – – – –

Determine the separator effective length for the gas capacity Determine the separator effective length for the liquid retention time Determine the biggest effective length Calculate the seam to seam length and select the biggest criteria Calculate the slenderness ratio

• Select the diameter based on – Adequate slenderness ratio to prevent re-entrainment – Other considerations (cost, overall size, etc…)

• If desired a sensitivity analysis on liquid retention time can be performed Mauricio Prado – The University of Tulsa

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Horizontal Separator Sizing - Example

• Example – – – – – – – – – – –

Gas flowrate 10 MM scf/d Gas specific gravity 0.6 Gas viscosity 0.013 cp Gas compressibility factor 0.84 Liquid flowrate 2000 bpd Liquid API 40 Liquid retention time 3 min Separator 50% filled with liquid Operating pressure 1000 psia Operating temperature 60 F Droplet size to be separated 140 micron

Mauricio Prado – The University of Tulsa

84

Horizontal Separator Sizing - Example

• Example

Liquid Retention Time – 3 min Diameter (in)

Effective Length (ft)

Seam to Seam Length (ft)

Slenderness ratio

16

33.5

44.7

33.5

20

21.4

28.6

17.2

24

14.9

19.9

9.9

30

9.5

12.7

5.1

36

6.6

9.6

3.2

42

4.9

8.4

2.4

48

3.7

7.7

1.9

Mauricio Prado – The University of Tulsa

85

Horizontal Separator Sizing - Example

• Example

Liquid Retention Time – 2 min Diameter (in)

Effective Length (ft)

Seam to Seam Length (ft)

Slenderness ratio

16

22.3

29.8

22.3

20

14.3

19.1

11.4

24

9.9

13.2

6.6

30

6.4

8.9

3.5

36

4.4

7.4

2.5

42

3.2

6.7

1.9

48

2.5

6.5

1.6

Mauricio Prado – The University of Tulsa

86

Horizontal Separator Sizing - Example

• Example

Liquid Retention Time – 1 min Diameter (in)

Effective Length (ft)

Seam to Seam Length (ft)

Slenderness ratio

16

11.2

14.9

11.2

20

7.1

9.5

5.7

24

5.0

7.0

3.5

30

3.2

5.7

2.3

36

2.2

5.2

1.7

42

1.6

5.1

1.5

48

1.2

5.2

1.3

Mauricio Prado – The University of Tulsa

87

Horizontal Separator Sizing - Example

• Example

Liquid Retention Time – 4 min Diameter (in)

Effective Length (ft)

Seam to Seam Length (ft)

Slenderness ratio

16

44.7

59.6

44.7

20

28.6

38.1

22.9

24

19.9

26.5

13.2

30

12.7

16.9

6.8

36

8.8

11.8

3.9

42

6.5

10.0

2.9

48

5.0

9.0

2.2

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88

Horizontal Separator Sizing - Example

• Example

Retention time (min)

Diameter (in)

Effective Length (ft)

Seam to Seam Length (ft)

Slenderness ratio

1

24

5.0

7.0

3.5

2

30

6.4

8.9

3.5

3

36

6.6

9.6

3.2

4

36

8.8

11.8

3.9

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Horizontal Separator Sizing - Analysis

• Those equations can also be used once a separator is installed to verify the performance depending on changes in operational parameters

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90

Vertical Separator Sizing

• Must determine – Separator height – Separator diameter

• Must satisfy – For a design gas capacity the separator must be able to remove liquid drops greater than a certain size – Provide sufficient residence time for the gas and liquid to reach equilibrium

• Usual Assumptions – Minimum drop size to be separate 100 micron

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91

Vertical Separator Sizing

• Gas capacity – For the droplets to fall towards the gas-liquid interface, the droplet terminal velocity must be greater than the gas velocity. This will yield a minimum separator diameter

Vt

Vg

Mauricio Prado – The University of Tulsa

qg

92

Vertical Separator Sizing

• Gas capacity – Droplet settling condition Gas flowrate

Gas velocity

Vg 

Minimum separator diameter

As 

qg As

2 d min

4

Separator Area

Temperature

q g  q gsc

Compressibility factor

T  460 14.7 Z 520 P Pressure

Gas flowrate standard conditions

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Vertical Separator Sizing

• Gas capacity – Droplet settling condition

F

scf/d

ft/s

Vg  6 10 5

q gsc T  460 Z d s2 P in

Mauricio Prado – The University of Tulsa

psia

94

Vertical Separator Sizing

• Gas capacity – Droplet settling condition

micron

Vg  6 10

5

ft/s

q T  460 Z sc g

d Vt  0.0119 Cd

d s2 P scf/d

in

2 d min  6 10 5

ft/s Mauricio Prado – The University of Tulsa

F

 l   g    g 

   

lb/ft3

q gsc T  460 Z Vt P psia 95

Vertical Separator Sizing

• In situ properties

lbm/ ft3 lbm/ ft3

141.5  131.5  API

 l  62.4 

ft3/ scf

lbm/ ft3

141.5  l  62.4 131.5  API

deg F psia

lbm/ ft3

g 

0.0764  g

Bg  0.028269

Bg ft3/scf

(T  460) Z P  14.7 

 g  2. 7

 gP (T  460) Z

psig

F

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Vertical Separator Sizing

• Gas capacity – Droplet settling condition micron

Vg  6 10

5

ft/s

q gsc T  460 Z

d Vt  0.0119 Cd

d s2 P scf/d

in

2 d min  6 10 5

ft/s

Mauricio Prado – The University of Tulsa

F

 l   g    g 

   

lb/ft3

q gsc T  460 Z Vt P psia

97

Vertical Separator Sizing

• Liquid capacity – Liquid retention time

Liquid residence time

Separator diameter

Liquid volume

Liquid height

V tl  ql

V

d s2 4

hl

Liquid flowrate

in in

min bpd

d s2 hl  8.58 tl ql

Mauricio Prado – The University of Tulsa

98

Vertical Separator Sizing

• Seam to Seam Length – After the effective separator length is calculate we provide necessary space for the gas separation area, mist extractor and space below the water outlet.

ft

in

in

 h  76 hl  d s  40  Lss  max l ,  12 12  

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99

Vertical Separator Sizing

• Slenderness ratio – Experience shows that slenderness ratio should be no greater than 4 to keep the height of the liquid collection section to a reasonable level – Usual values are around 3 to 4

ft

12 Lss sr  d in

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Vertical Separator Sizing

• Determine gas flowrate, gas density, gas viscosity, liquid flowrate and API • Determine operating temperature and pressure • Determine the liquid retention time • Calculate in-situ properties • Determine the minimum drop size to be separated • Calculate drop terminal settling velocity • Calculate the minimum separator diameter • For several diameters bigger than the minimum one – Determine the liquid height – Determine the seam to seam length – Determine the slenderness ratio

• Select the diameter based on – Adequate slenderness ratio to have a reasonable liquid height – Other considerations (cost, overall size, etc…)

• If desired a sensitivity analysis on liquid retention time can be performed Mauricio Prado – The University of Tulsa

101

Vertical Separator Sizing - Example

• Example – – – – – – – – – – –

Gas flowrate 10 MM scf/d Gas specific gravity 0.6 Gas viscosity 0.013 cp Gas compressibility factor 0.84 Liquid flowrate 2000 bpd Liquid API 40 Liquid retention time 3 min Separator 50% filled with liquid Operating pressure 1000 psia Operating temperature 60 F Droplet size to be separated 140 micron

Mauricio Prado – The University of Tulsa

102

Vertical Separator Sizing - Example

• Example

Liquid Retention Time – 3 min Diameter (in)

Liquid Height (in)

Seam to Seam Length (ft)

Slenderness ratio

24

89.4

13.8

6.9

30

57.2

11.1

4.4

36

39.7

9.6

3.2

42

29.2

9.3

2.6

48

22.3

9.2

2.3

Mauricio Prado – The University of Tulsa

103

Vertical Separator Sizing - Example

• Example

Liquid Retention Time – 2 min Diameter (in)

Liquid Height (in)

Seam to Seam Length (ft)

Slenderness ratio

24

59.6

11.3

5.6

30

38.1

9.5

3.8

36

26.5

8.5

2.8

42

19.5

8.5

2.4

48

14.9

8.6

2.1

Mauricio Prado – The University of Tulsa

104

Vertical Separator Sizing - Example

• Example

Liquid Retention Time – 1 min Diameter (in)

Liquid Height (in)

Seam to Seam Length (ft)

Slenderness ratio

24

29.8

8.8

4.4

30

19.1

7.9

3.2

36

13.2

7.4

2.5

42

9.7

7.6

2.2

48

7.4

8.0

2.0

Mauricio Prado – The University of Tulsa

105

Vertical Separator Sizing - Example

• Example

Liquid Retention Time – 4 min Diameter (in)

Liquid Height (in)

Seam to Seam Length (ft)

Slenderness ratio

24

119.2

16.3

8.1

30

76.3

12.7

5.1

36

53.0

10.7

3.6

42

38.9

10.1

2.9

48

29.8

9.8

2.5

Mauricio Prado – The University of Tulsa

106

Vertical Separator Sizing - Example

• Example

Retention time (min)

Diameter (in)

Liquid Height (in)

Seam to Seam Length (ft)

Slenderness ratio

1

30

19.1

7.9

3.2

2

30

38.1

9.5

3.8

3

36

39.7

9.6

3.2

4

36

53.0

10.7

3.6

Mauricio Prado – The University of Tulsa

107

Separator Sizing Project

• Develop a spreadsheet to size both horizontal and vertical separators. • Use the spreadsheet to design a horizontal and a vertical separator for the following conditions: – – – – – – – – – –

Gas flowrate 15 MM scf/d Gas specific gravity 0.72 Gas viscosity 0.015 cp Gas compressibility factor 0.82 Liquid flowrate 4000 bpd Liquid API 25 Liquid retention time 3 min Operating pressure 600 psia Operating temperature 60 F Droplet size to be separated 140 micron

• Present your results as if this was a technical report you submitted to support your design calculations Mauricio Prado – The University of Tulsa

108

Single Phase Flow

Gas Metering

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Gas Metering

• Natural gas can not be easily stored as crude or other liquid hydrocarbons • Once produced, natural gas must be delivered to its final usage (sales or re-injection) • In either case, the amount of gas produced must be measured • Both gas and liquid flow can be measured in volumetric or mass flow rates. These measurements can be converted between one another if the material's density is known • The density for a liquid is almost independent of the liquid conditions; however, this is not the case for a gas, the density of which depends greatly upon pressure, temperature and to the gas composition

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110

Gas Metering

• Gases are compressible and change volume when placed under pressure or are heated or cooled. A volume of gas under one set of pressure and temperature conditions is not equivalent to the same gas under different conditions • References will be made to "actual" flow rate through a meter and "standard" flow rate through a meter • Gas mass flow rate can be directly measured, independent of pressure and temperature effects, with thermal mass flow meters, Coriolis mass flow meters, or mass flow controllers Mauricio Prado – The University of Tulsa

111

Flow Meter Types

• Numerous types of flow meters exist • They can be classified as – – – –

Differential pressure Positive displacement Velocity Mass meters

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Differential Pressure Meters

• Differential pressure meters include – – – – – –

Orifice Plate Venturi Tube Flow Nozzle Pitot Tube Target Variable-Area (Rota meter)

• The basic operating principle of differential pressure flowmeters is the fact that the pressure drop across the meter is a function of the flow rate. The flow rate is obtained by measuring the pressure differential and using the calibration relationship • They consist of two elements – The primary element causes a change in kinetic energy, which creates the differential pressure in the pipe – The secondary element measures the differential pressure Mauricio Prado – The University of Tulsa

113

Differential Pressure Meters – Orifice Plate

• An orifice is simply a flat piece of metal with a specificsized hole bored in it. Most orifices are of the concentric type, but eccentric, conical (quadrant), and segmental designs are also available • In practice, the orifice plate is installed in the pipe between two flanges. Acting as the primary device, the orifice constricts the flow to produce a differential pressure across the plate. Pressure taps on either side of the plate are used to detect the difference

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114

Differential Pressure Meters – Orifice Plate

• Metering accuracy of all orifice flowmeters depends on the installation conditions, the orifice area ratio, and the physical properties of the fluid being measured • Major advantages of orifices are that they have no moving parts and their cost does not increase significantly with pipe size

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115

Differential Pressure Meters – Venturi Tube

• Venturi tubes have the advantage of being able to handle large flow volumes at low pressure drops • A venturi tube is essentially a section of pipe with a tapered entrance and a straight throat. As liquid passes through the throat, its velocity increases, causing a pressure differential between the inlet and outlet regions

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116

Differential Pressure Meters – Venturi Tube

• The flowmeters have no moving parts. They can be installed in large diameter pipes using flanged, welded or threaded-end fittings. Four or more pressure taps are usually installed with the unit to average the measured pressure

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117

Differential Pressure Meters – Flow Nozzle

• Flow Nozzles, at high velocities, can handle approximately 60 percent greater liquid flow than orifice plates having the same pressure drop

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118

Differential Pressure Meters – Pitot Tube

• Pitot tubes sense two pressures simultaneously, impact and static • The impact unit consists of a tube with one end bent at right angles toward the flow direction. The static tube's end is closed, but a small slot is located in the side of the unit • The units are susceptible to plugging

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119

Differential Pressure Meters – Target

• Target meters sense and measure forces caused by liquid impacting on a target or drag-disk suspended in the stream. A direct indication of the flow rate is achieved by measuring the force exerted on the target • Target meters are useful for measuring flows of dirty or corrosive fluids

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120

Differential Pressure Meters – Variable Area or Rotameters

• Consist essentially of a tapered tube and a float • When there is no flow, the float rests freely at the bottom of the tube. As fluid enters the bottom of the tube, the float begins to rise. The float is selected so as to have a density higher than that of the fluid and the position of the float varies directly with the flow rate. Its exact position is at the point where the differential pressure between the upper and lower surfaces balance the weight of the float • Because the flow rate can be read directly on a scale mounted next to the tube, no secondary flow-reading devices are necessary. However, if desired, automatic sensing devices can be used to sense the float's level and transmit a flow signal

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121

Positive Displacement Meters

• Positive displacement meters include – – – – – –

Reciprocating Piston Oval Gear Nutating Disk Rotary Vane Rotating Lobe Rotating Impeller

• Operation of these units consists of separating fluids into accurately measured increments and moving them on. Each segment is counted by a connecting register. Because every increment represents a discrete volume, positive-displacement units are popular for automatic batching and accounting applications • Positive-displacement meters are good candidates for measuring the flows of viscous liquids or for use where a simple mechanical meter system is needed Mauricio Prado – The University of Tulsa

122

Positive Displacement Meters – Reciprocating Piston

• Piston meters can be used to handle a wide variety of liquids

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123

Positive Displacement Meters – Oval Gear

• Uses two or more oblong gears configured to rotate at right angles to one another, forming a tee shape • As the fluid pushes the gears, it rotates them, allowing the fluid in the measurement chamber to be released into the outlet port. Meanwhile, fluid entering the inlet port will be driven into the measurement chamber, which is now open • This cycle continues as the gears rotate and fluid is metered through alternating measurement chambers

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124

Positive Displacement Meters – Nutating Disk

• • •

The fluid enters in one side of the meter and strikes the nutating disk, which is eccentrically mounted The disk must then "wobble" or nutate about the vertical axis, since the bottom and the top of the disk remain in contact with the mounting chamber A partition separates the inlet and outlet chambers. As the disk nutates, it gives direct indication of the volume of the liquid that has passed through the meter as volumetric flow is indicated by a gearing and register arrangement, which is connected to the disk

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125

Positive Displacement Meters – Rotary Vane

• Rotating vane meters have spring-loaded vanes that entrap increments of liquid between the eccentrically mounted rotor and the casing. The rotation of the vanes moves the flow increment from inlet to outlet and discharge

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126

Positive Displacement Meters – Rotating Lobe and Rotating Impeller

• Rotating lobe and impeller meters are variations of the oval gear flowmeter that do not share its precise gearing • As the lobes or impellers rotate, a fixed volume of liquid is entrapped and then transported toward the outlet

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127

Velocity Meters

• Velocity meters include – – – – – –

Turbine Vortex Shedding Conada Effect & Momentum Exchange Electromagnetic Ultrasonic, Doppler Ultrasonic, Transit-Time

• These instruments operate linearly with respect to the volume flow rate • Because there is no square-root relationship (as with differential pressure devices), their rangeability is greater Mauricio Prado – The University of Tulsa

128

Velocity Meters – Turbine • • •

The unit consists of a multiple-bladed rotor mounted with a pipe, perpendicular to the liquid flow The rotor spins as the liquid passes through the blades. The rotational speed is a direct function of flow rate and can be sensed by magnetic pick-up, photoelectric cell, or gears The number of electrical pulses counted for a given period of time is directly proportional to flow volume. A tachometer can be added to measure the turbine's rotational speed and to determine the liquid flow rate

Mauricio Prado – The University of Tulsa

129

Velocity Meters – Vortex •

•

Vortex meters make use of a natural phenomenon that occurs when a liquid flows around a bluff object. Eddies or vortices are shed alternately downstream of the object. The frequency of the vortex shedding is directly proportional to the velocity of the liquid flowing through the meter The three major components of the flowmeter are a bluff body strut-mounted across the flowmeter bore, a sensor to detect the presence of the vortex and to generate an electrical impulse, and a signal amplification and conditioning transmitter whose output is proportional to the flow rate

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130

Mass Meters

• Mass meters include – Coriolis – Thermal

• The continuing need for more accurate flow measurements in mass-related processes has resulted in the development of mass flowmeters

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131

Mass Meters – Coriolis

• Gustav Gaspard Coriolis, a French engineer, who first noted that all bodies moving on the surface of the Earth tend to drift sideways because of the eastward rotation of the planet • In the Northern Hemisphere the deflection is to the right of the motion; in the Southern, it is to the left. This drift plays a principal role in both the tidal activity of the oceans and the weather of the planet

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132

Mass Meters – Coriolis •

•

•

The first industrial Coriolis patents date back to the 1950s, and the first Coriolis mass flowmeters were built in the 1970s. These flowmeters artificially introduce a Coriolis acceleration into the flowing stream and measure mass flow by detecting the resulting angular momentum When a fluid is flowing in a pipe and it is subjected to Coriolis acceleration through the mechanical introduction of apparent rotation into the pipe, the amount of deflecting force generated by the Coriolis inertial effect will be a function of the mass flow rate of the fluid If a pipe is rotated around a point while liquid is flowing through it (toward or away from the center of rotation), that fluid will generate an inertial force (acting on the pipe) that will be at right angles to the direction of the flow

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133

Mass Meters – Thermal • • •

Thermal mass flowmeters are most often used for the regulation of low gas flows They operate either by introducing a known amount of heat into the flowing stream and measuring an associated temperature change, or by maintaining a probe at a constant temperature and measuring the energy required to do so The components of a basic thermal mass flowmeter include two temperature sensors and an electric heater between them

Mauricio Prado – The University of Tulsa

134

Orifice Plate Metering

• •

Orifice plates are probably the most widely used form of measuring gas flow rate The common locations for the pressure measurements are – Pipe taps – Vena contracta taps – Flange taps

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135

Orifice Plate Metering •

The equations used to determine the flowrate are described in details on the AGA Report Number 3 – “Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids The equations are similar to the ones used to describe the pressure drop through restrictions It is written in a more “practical” way be lumping several variables into coefficients Basically the equation is of the form:

• • •

ft3/h

Differential pressure in inches of water at 60F

q  C hw Pf

Static pressure in psia

'

C '  Fb Fr Y Fpb Ftb Ftf Fg Fpv Fm Fl Fa

• • • • • • • • • • •

Fb Fr Y Fpb Ftb Ftf Fg Fpv Fm Fl Fa

Orifice factor depend on orifice size and tap location Reynolds number correction factor Expansion factor Pressure base factor Temperature base factor Flowing temperature factor Specific gravity factor Supercompressibility factor (Z) Manometer factor (for mercury meter) Gauge location factor Orifice thermal expansion factor

Mauricio Prado – The University of Tulsa

136

Acid Gas Treating

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137

Introduction

• In addition to heavy hydrocarbons ends and water vapor, natural gas or associated gas often contains other contaminants that may be removed • CO2, H2S and other sulfur compounds such as mercaptans may require complete or partial removal to be accepted by a gas purchaser • These compounds are known as “acid gases” – CO2 and H2S in the presence of water may form weak acids, thus the term acid gas

• Produced gas with H2S or other sulfur components is also called sour gas while gases with only CO2 are called sweet • Both H2S and CO2 are undesirable products since they cause – – – –

Corrosion Reduce heating value In addition H2S is toxic !!! May cause hydrogen embrittlement

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138

Introduction

Mauricio Prado – The University of Tulsa

139

Introduction

• Gas Sweetening Processes – – – – – – –

Solid bed absorption Chemical solvents Physical solvents Direct conversion of H2S to sulfur Sulfide scavenger Distillation Gas permeation

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140

Solid bed absorption

• A fixed bed of solid particles can be used to remove acid gases • Gas stream flow through a bed of solid particles that absorb the gas either through chemical reaction or ionic bonding • When the bed is saturated with acid gases, the vessel must be removed from service and the bed regenerated or replaced • There are several types – Iron sponge – Zinc oxide – Molecular sieves

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141

Iron Sponge

• Uses chemical reaction of ferric oxide with H2S to sweeten gas streams • 2Fe2O3 + 6H2S → 2Fe2S3 + 6H2O • Applied to gases with low H2S concentrations (300 ppm) at low to moderate pressures (50 – 500 psig) • Requires presence of slightly alkaline water (pH 8 – 10) and temperature below 110 oF • The ferric oxide is impregnated on wood chips • The chips are contained in a vessel and sour gas flows through the bed and reacts with the ferric oxide Mauricio Prado – The University of Tulsa

142

Iron Sponge

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Iron Sponge

• The ferric sulfide generated can be oxidized with air producing sulfur and regenerating the ferric oxide • 2Fe2S3 + 3O2 → 2Fe2O3 + 6S • The regeneration step must be performed with great care as the reaction is exothermic !!!

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144

Zinc Oxide

• Similar to the iron sponge • Solid bed of granular zinc oxide is used to react with H2S • ZnO + H2S → ZnS + H2O • High temperature (>250 oF) is required to increase the diffusion rate • Saturated bed is discharged by gravity flow and contains up to 20% sulfur • Use is decreasing due to disposal problems

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145

Molecular Sieves

• Synthetically manufactured solid porous zeolite with all the pores exactly the same size • Polar charges are created within pores call active sites. Polar gases molecules such as H2S and water bonds at the active sites. • Molecular sieve units will dehydrate gas as well as sweeten it • Molecular sieve bed can be regenerated indefinitely by flowing hot sweet gas through the bed at temperature of 300 – 400 oF • Suitable for small gas stream, polishing application or deep dehydration Mauricio Prado – The University of Tulsa

146

Chemical solvents

• Use an aqueous solution of a weak base to react with and absorb the acid gases in natural gas stream • The reactions are reversible by changing the system temperature or pressure, or both. • The aqueous base solution can be regenerated and thus circulated in a continuous cycle • Most chemical solvent processes use either an amine or carbonate solution

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Chemical solvents - Amine

• In a typical amine system, sour gas enters the system through an inlet separator to remove entrained water and hydrocarbon liquids • The gas then goes to the bottom of the amine absorber and flows counter-current to the amine solution • The amine solution leaves the bottom of the absorber unit carrying the acid gases. This solution is referred to rich amine (amine + CO2 +H2S)

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Chemical solvents - Amine

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Chemical solvents - Amine

• The rich amine is flashed to a flash tank to remove almost all the dissolved hydrocarbon gases and condensates • From the flash tank the rich amine proceeds to the rich/lean amine stripping tower • In the stripping tower the heat from a reboiler breaks the bonds between the amine and the acid gases • The acid gases leave from the top of the stripping tower and the lean amine leaves from the bottom of the vessel • The hot amine is cooled in an exchanger (where it also heats the rich amine) and then is pumped back to the top of the absorber

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Physical solvents

• This process is based on the solubility of H2S and CO2 within the solvent instead of chemical reactions • Solubility depends on temperature and pressure • High pressures and lower temperatures increase solubility of acid gases • Various organic solvents are used to absorb acid gases • Regeneration of the solvent is accomplished by flashing to lower pressures or stripping with a lean gas • The physical solvents can have also affinity for some heavy hydrocarbons which means a loss of heavier fractions Mauricio Prado – The University of Tulsa

151

Physical solvents

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Direct Conversion to H2S

• Chemical solvents and physical solvents have a problem that the H2S and CO2 must be discarded • The release of H2S in the atmosphere may be limited by environmental regulations • The acid by-product gases can be directed to a flare which converts H2S to SO2 • SO2 release to the atmosphere is also a problem • Direct conversion process to sulfur use chemical reactions to oxidize H2S and produce sulfur and water Mauricio Prado – The University of Tulsa

153

Direct Conversion to H2S

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Direct Conversion to H2S

• Those processes uses specialized catalysts and solvents • Pure sulfur is produced and small amounts of SO2 are generated and can be flared

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Sulfide scavengers

• Sour gas sweetening can also be carried out continuously in the flowline by injection of H2S scavengers • The most scavenge is amine-aldehyde condensate • Contact time should be around 30s • Limited to gas streams between ½ to 15 MMscf/d containing less than 100 ppm of H2S • Advantages – Low operating temperature – Low corrosiveness – No reactivity to hydrocarbons

• Limitations – Limited to gas streams between ½ to 15 MMscf/d containing less than 100 ppm of H2S

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156

Distillaton

• The Ryan-Holmes distillation process uses cryogenic distillation to remove acid gases • Usually used to remove CO2 from LPG (Liquefied Petroleum Gas) • It is a very complicated process • Used also to generate CO2 at high pressure for reservoir injection

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157

Process selection

• Facts to consider – – – –

Type of acid gas to be removed Concentration Production volume Feasibility of recovering sulfur

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158

Gas permeation

• Based on the diffusion of gas through a permeable membrane • Something like “filtering” gas • Effective to remove CO2 but not very adequate for H2S

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159

Gas Dehydration

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Introduction

• Gas dehydration is the process of removing water vapor from a gas stream • The purpose is to reduce the temperature at which water will condense from the gas. • It is required since most gas sales contract specify a maximum amount for the water vapor content • The presence of vapor can cause – Hydrate formation – Corrosion – Slugging in gas lines

• The capacity of gas to hold water is reduced if the gas is compressed or cooled • Compression and cooling can reduce the content of water in the gas, but the gas is still saturated with vapor for that pressure and temperature. Further reduction in temperature or increase in pressure can cause again water to condense • The basic mechanisms used to dehydrate gas are: – Glycol dehydration – Solid bed adsorption Mauricio Prado – The University of Tulsa

161

Water content

• The first step is the determination of the water content of the gas • The water content depends on the gas composition, temperature and pressure • For sweet natural gases containing over 70% methane and small amounts of heavy ends, the McKetta-Wehe P-T correlation can be used

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162

Water content

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Water content

• Example – What is the water content of a natural gas with a molecular weight of 26 in equilibrium with a 3% brine at a pressure of 3000 psi and a temperature of 150 F – From the graph • • • •

Water content – 104 lb of water / MMscf gas Correction for salinity – 0.93 Correction for molecular weight – 0.98 Final content – 94.8 lb/MMscf

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Dehydration

• The gas is put in contact with a hygroscopic substance – Liquid desiccant – Solid desiccant

• Desiccant is substance that has an affinity for water • Usually the choice of dehydration methods is between glycol and solid desiccants

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Dehydration

• Liquid desiccant – Glycol dehydration is by far the most common process

• Solid Desiccants (alumina, silica gel, molecular sieves): – Characterized by porous structure that contains very large internal surface areas ( 200-800 m2/g) with very small radii of curvature (0.001-0.2 microns) – Strong affinity for water – Capacities between 5-15% by weight – Can dry gas to less than 0.1 ppm of water or a dew point of –150 oF

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Dehydration

• Advantages of Glycol over Solid Desiccants: – Lower installation cost (Solid desiccant plants cost 50% more at 10 MMscfd and 33% more at 50 MMscfd) – Lower pressure drop (5-10 psi vs. 10-50 psi for dry desiccants) – Glycol dehydration is continuous rather than batch – Glycol makeup is easily accomplished – Glycol units require less regeneration heat per pound of water removed – Glycol units can typically dehydrate natural gas to 0.5 lbm H2O/MMscf

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Dehydration

• Disadvantages of Glycol over Solid Desiccants: – Water dew points below –25 oF require stripping gas and a Stahl column – Glycol is susceptible to contamination – Glycol is corrosive when contaminated or decomposed

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Dehydration

• Advantages of Solid Desiccants: – Dew points as low as –150 oF – They are less affected by small changes in gas pressure, temperature and flow rate – They are less susceptible to corrosion or foaming

• Disadvantages Solid Desiccants: – Higher capital cost and higher pressure drops – Desiccant poisoning by heavy hydrocarbons, H2S, CO2, etc. – Mechanical breaking of desiccant particles – High regeneration heat requirements and high utility costs

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Dehydration

• Bottom Line: – Glycol dehydration is by far the most common process – When very low dew points are required then solid desiccants are used

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Glycol dehydration

• This is the most common method of dehydration • The gas is put in contact with a hygroscopic liquid (glycol) • The water vapor is dissolved into the pure glycol • Inexpensive system • Glycol can be regenerated by “boiling” the water out

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Glycol dehydration

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Glycol dehydration

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Glycol dehydration

• Choices of glycol – – – –

Ethylene Glycol (EG) Diethylene Glycol (DEG) Triethylene Glycol (TEG) Tetraethylene Glycol (TREG)

• TEG has gained almost universal acceptance as the most cost-effective choice because: – TEG is more easily regenerated – TEG has a higher decomposition temperature of 404 oF while DEG is 328 oF – Vaporization losses are lower than EG or DEG – TEG is not too viscous above 70 oF

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DEG EG TEG TREG

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Glycol dehydration

• Usually the glycol dehydration process is continuous • Gas and glycol flow in counter current flow through the vessel (contactor or absorber) • The gas in contact with the glycol looses water and the glycol absorb water vapor • The contactor works in the same principle as a condensate stabilizer Mauricio Prado – The University of Tulsa

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Glycol dehydration

• The dry gas leaves from the top and the rich glycol leaves from the bottom • The rich glycol then goes to a regeneration unit where the water is removed and the dry glycol is then pumped back to the contactor • The glycol will also absorb heavy hydrocarbons, therefore it is important that the wet gas goes through a scrubber to remove liquid and solid impurities before entering the contactor

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Glycol dehydration

• Dry gas from the top of the contactor flows through an external gas/glycol heat exchanger to cool the glycol and increase its capacity to absorb water and decrease its tendency to flash inside the contactor

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Glycol dehydration

• The wet glycol goes to the reflux column where it is heated and looses water vapor • The water vapor leaves from the top of the reflux column

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Glycol dehydration

• The resulting heated glycol toes to a low pressure separator where the remaining hydrocarbon gas and liquids are removed • The gas from the separator can be used as fuel gas • The dry glycol is then pumped back to the contactor

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Gas Processing

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Introduction

• The term gas processing refers to the processes of removing ethane, propane, butane and heavier components from the gas stream • The components heavier than methane can be sold as a combined mixture known as NGL (Natural Gas Liquids) or can be sold as “pure” components know as LPG (Liquefied Petroleum Gases) • It is usually more economical so extract and sell those fractions as liquids event though their removal may reduce the heating value of the produced gas. The extra revenue from the sale of liquids is usually significantly higher than the decrease in heating value of the gas • Also it is important to remember that natural gas must have a maximum heating limit set by contract. Too rich natural gas may not work properly in burners that are designed for lower heating values • The processes use to extract LPG and NGL are – Absorption/lean oil – Refrigeration – Cryogenic plants

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Absorption

• In this process a kerosene type oil is circulated through the plant • This oil absorb light hydrocarbon components from the gas • The light components are then separated from the rich kerosene and the kerosene is recycled

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Absorption

• The inlet gas is cooled by a heat exchanger before entering the absorber • The absorber is a contact tower similar to a glycol unit • The lean absorber oil trickles over trays while the gas flows up in countercurrent flow with the lean oil

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Absorption

• The residual gas leaves at the top • The absorber oil leaves from the bottom and goes to the rich oil de-ethanizer or de-methanizer to remove methane and/or ethane as a flash gas • The de-ethanizer works like a cold feed stabilizing the rich oil in the higher fractions and removing ethane and methane

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Absorption

• In the de-ethanizer heat is added at the bottom driving off almost all methane and ethane by exchanging heat with the hot lean oil coming from the still • Absorber oil then goes to a still where it is heated to a high enough temperature to drive the propane, butane and pentane and other natural gas liquid components to the overhead. A temperature control on a condenser keeps lean oil from being lost with the overhead gas

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Absorption

• • • •

Lean oil is now ready to be pumped back to the absorber These plants are not common nowadays. They are difficult to operate Typical recoveries – Propane – 80% – Butane – 90% – Pentane plus – 98%

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Refrigeration

• In a refrigeration plant inlet gas is cooled to a low temperature to condese the desired fraction of LPG and NGL • Either freon or propane is used as the refrigerant • The water must be removed before the process or we run the risk or having hydrates

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Refrigeration

• It is common to inject glycol in the gas after the free water separation if the gas is not coming from a de-hydration unit • The chiller is usually a kettle type exchanger • Freon is able to cool the gas to -15F and propane can cool the gas to -40F • The cooled mixture is then separated in a cold separator

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Refrigeration • • • • •

Water and glycol comes from the bottom Hydrocarbon liquids are routed to the distillation tower and gas flows from the top The tower operates in the same way as a condensate stabilizer The inlet stream is heated The recovery for this process are – – –

Propane – 85% Butane – 94 % Pentane plus – 98%

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Cryogenic plants

• In a typical cryogenic plant the gas is refrigerated to 100 up to -150F by expansion through a turbine • The gas is routed through heat exchangers where it is cooled by the residue gas • Condensed liquids are injected into de de-methanizer • The gas is then expanded and the cold gas enter the demethanizer

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Cryogenic plants

• Cryogenic plants are the most common design currently used • They are simple to operate and easy to package • They may be expensive • Typical recoveries are – Ethane – 60% – Propane – 90% – Butane plus – 100%

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NGL to LPG

• The liquids from a gas processing platn may be sold as NGL • This is common for small isolated plants • Often it is more economical to separate the NGL into several components and sell them as LPG (ethane, propane, butane, and natural gasoline) • The process of separating those liquids is called fractionation

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Fractioning

• The liquid is cascaded through a series of distillation towers where successively heavier and heavier components are separated as overhead gas

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Natural Gas Production

Natural Gas Storage

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Introduction

• Natural gas, like most other commodities, can be stored for an indefinite period of time • The exploration, production, and transportation of natural gas takes time, and the natural gas that reaches its destination is not always needed right away, so it is injected into underground storage facilities • These storage facilities can be located near market centers that do not have a ready supply of locally produced natural gas • The type of storage facility depends on its usage. Two uses for natural gas in storage facilities – meeting base load requirements, and – meeting peak load requirements

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Storage Usage

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Base load – Base load storage capacity is used to meet seasonal demand increases – Base load facilities are capable of holding enough natural gas to satisfy long term seasonal demand requirements – Typically, the turn-over rate for natural gas in these facilities is a year; natural gas is generally injected during the summer (non-heating season), which usually runs from April through October, and withdrawn during the winter (heating season), usually from November to March – These reservoirs are larger, but their delivery rates are relatively low, meaning the natural gas that can be extracted each day is limited. Instead, these facilities provide a prolonged, steady supply of natural gas – Depleted gas reservoirs are the most common type of base load storage facility

•

Peak load – Peak load storage facilities, on the other hand, are designed to have highdeliverability for short periods of time, meaning natural gas can be withdrawn from storage quickly should the need arise – Peak load facilities are intended to meet sudden, short-term demand increases – These facilities cannot hold as much natural gas as base load facilities; however, they can deliver smaller amounts of gas more quickly, and can also be replenished in a shorter amount of time than base load facilities – While base load facilities have long term injection and withdrawal seasons, turning over the natural gas in the facility about once per year, peak load facilities can have turn over rates as short as a few days or weeks – Salt caverns are the most common type of peak load storage facility, although aquifers may be used to meet these demands as well

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Storage Types

• Natural gas storage can be: – Underground • Depleted gas reservoirs • Aquifers • Salt caverns

– Liquefied natural gas • LNG allows natural gas to be shipped and stored in liquid form, meaning it takes up much less space than gaseous natural gas

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Underground Storage

• Underground Storage – Essentially, any underground storage facility is reconditioned before injection, to create a sort of storage vessel underground – Natural gas is injected into the formation, building up pressure as more natural gas is added – In this sense, the underground formation becomes a sort of pressurized natural gas container – As with newly drilled wells, the higher the pressure in the storage facility, the more readily gas may be extracted – Once the pressure drops to below that of the wellhead, there is no pressure differential left to push the natural gas out of the storage facility – This means that, in any underground storage facility, there is a certain amount of gas that may never be extracted. This is known as physically unrecoverable gas; it is permanently embedded in the formation

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Underground Storage

• Underground Storage – 'Working gas' is the volume of natural gas in the storage reservoir that can be extracted during the normal operation of the storage facility – This is the natural gas that is being stored and withdrawn; the capacity of storage facilities normally refers to their working gas capacity – At the beginning of a withdrawal cycle, the pressure inside the storage facility is at its highest; meaning working gas can be withdrawn at a high rate – As the volume of gas inside the storage facility drops, pressure (and thus deliverability) in the storage facility also decreases – Periodically, underground storage facility operators may reclassify portions of working gas as base gas after evaluating the operation of their facilities

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Depleted Gas Reservoirs

• Depleted Gas Reservoirs – The most prominent and common form of underground storage consists of depleted gas reservoirs. Depleted reservoirs are those formations that have already been tapped of all their recoverable natural gas. This leaves an underground formation, geologically capable of holding natural gas. In addition, using an already developed reservoir for storage purposes allows the use of the extraction and distribution equipment left over from when the field was productive. Having this extraction network in place reduces the cost of converting a depleted reservoir into a storage facility. Depleted reservoirs are also attractive because their geological characteristics are already well known. Of the three types of underground storage, depleted reservoirs, on average, are the cheapest and easiest to develop, operate, and maintain.

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Depleted Gas Reservoirs

• Depleted Gas Reservoirs – The first instance of natural gas successfully being stored underground occurred in Weland County, Ontario, Canada, in 1915 – This storage facility used a depleted natural gas well that had been reconditioned into a storage field – In the United States, the first storage facility was developed just south of Buffalo, New York – By 1930, there were nine storage facilities in six different states. Prior to 1950, virtually all natural gas storage facilities were in depleted reservoirs

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Depleted Gas Reservoirs

• Depleted Gas Reservoirs – The factors that determine whether or not a depleted reservoir will make a suitable storage facility are • Geographic – Geographically, depleted reservoirs must be relatively close to consuming regions. They must also be close to transportation infrastructure, including trunk pipelines and distribution systems

• Geologic – Geologically, depleted reservoir formations must have high permeability and porosity – The porosity of the formation determines the amount of natural gas that it may hold, while its permeability determines the rate at which natural gas flows through the formation, which in turn determines the rate of injection and withdrawal of working gas – In certain instances, the formation may be stimulated to increase permeability

– In order to maintain pressure in depleted reservoirs, about 50 percent of the natural gas in the formation must be kept as cushion gas. However, depleted reservoirs, having already been filled with natural gas and hydrocarbons, do not require the injection of what will become physically unrecoverable gas; that gas already exists in the formation Mauricio Prado – The University of Tulsa

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Aquifers

• Aquifers – Aquifers are the least desirable and most expensive type of natural gas storage facility for a number of reasons – First, the geological characteristics of aquifer formations are not as thoroughly known, as with depleted reservoirs – A significant amount of time and money goes into discovering the geological characteristics of an aquifer, and determining its suitability as a natural gas storage facility – Seismic testing must be performed, much like is done for the exploration of potential natural gas formations – The area of the formation, the composition and porosity of the formation itself, and the existing formation pressure must all be discovered prior to development of the formation – In addition, the capacity of the reservoir is unknown, and may only be determined once the formation is further developed

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Aquifers

• Aquifers – Aquifers are underground porous, permeable rock formations that act as natural water reservoirs – However, in certain situations, these water containing formations may be reconditioned and used as natural gas storage facilities – As they are more expensive to develop than depleted reservoirs, these types of storage facilities are usually used only in areas where there are no nearby depleted reservoirs – Traditionally, these facilities are operated with a single winter withdrawal period, although they may be used to meet peak load requirements as well

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Aquifers

• Aquifers – In order to develop a natural aquifer into an effective natural gas storage facility, all of the associated infrastructure must also be developed – This includes installation of wells, extraction equipment, pipelines, dehydration facilities, and possibly compression equipment – Since aquifers are naturally full of water, in some instances powerful injection equipment must be used, to allow sufficient injection pressure to push down the resident water and replace it with natural gas – While natural gas being stored in aquifers has already undergone all of its processing, upon extraction from a water bearing aquifer formation the gas typically requires further dehydration prior to transportation, which requires specialized equipment near the wellhead – Aquifer formations do not have the same natural gas retention capabilities as depleted reservoirs – This means that some of the natural gas that is injected escapes from the formation, and must be gathered and extracted by 'collector' wells, specifically designed to pick up gas that may escape from the primary aquifer formation Mauricio Prado – The University of Tulsa

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Aquifers

• Aquifers – In addition to these considerations, aquifer formations typically require a great deal more 'cushion gas' than do depleted reservoirs – Since there is no naturally occurring gas in the formation to begin with, a certain amount of natural gas that is injected will ultimately prove physically unrecoverable – In aquifer formations, cushion gas requirements can be as high as 80 percent of the total gas volume – While it is possible to extract cushion gas from depleted reservoirs, doing so from aquifer formations could have negative effects, including formation damage – As such, most of the cushion gas that is injected into any one aquifer formation may remain unrecoverable, even after the storage facility is shut down

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Aquifers

• Aquifers – All of these factors mean that developing an aquifer formation as a storage facility can be time consuming and expensive – In some instances, aquifer development can take 4 years, which is more than twice the time it takes to develop depleted reservoirs as storage facilities – In addition to the increased time and cost of aquifer storage, there are also environmental restrictions to using aquifers as natural gas storage – In the early 1980's the Environmental Protection Agency (EPA) set certain rules and restrictions on the use of aquifers as natural gas storage facilities – These restrictions are intended to reduce the possibility of fresh water contamination. Learn more about the Underground Injection Control program at the EPA

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Salt Caverns

• Salt Caverns – Underground salt formations offer another option for natural gas storage – These formations are well suited to natural gas storage in that salt caverns, once formed, allow little injected natural gas to escape from the formation unless specifically extracted – The walls of a salt cavern also have the structural strength of steel, which makes it very resilient against reservoir degradation over the life of the storage facility – Essentially, salt caverns are formed out of existing salt deposits – These underground salt deposits may exist in two possible forms: • Salt domes – Salt domes are thick formations created from natural salt deposits that, over time, leach up through overlying sedimentary layers to form large dome-type structures. They can be as large as a mile in diameter, and 30,000 feet in height. Typically, salt domes used for natural gas storage are between 6,000 and 1,500 feet beneath the surface, although in certain circumstances they can come much closer to the surface

• Salt beds – Salt beds are shallower, thinner formations. These formations are usually no more than 1,000 feet in height. Because salt beds are wide, thin formations, once a salt cavern is introduced, they are more prone to deterioration, and may also be more expensive to develop than salt domes

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Salt Caverns

•

Salt Caverns – Once a suitable salt dome or salt bed deposit is discovered, and deemed suitable for natural gas storage, it is necessary to develop a 'salt cavern' within the formation – Essentially, this consists of using water to dissolve and extract a certain amount of salt from the deposit, leaving a large empty space in the formation – This is done by drilling a well down into the formation, and cycling large amounts of water through the completed well – This water will dissolve some of the salt in the deposit, and be cycled back up the well, leaving a large empty space that the salt used to occupy – This process is known as 'salt cavern leaching' – Salt cavern leaching is used to create caverns in both types of salt deposits, and can be quite expensive – However, once created, a salt cavern offers an underground natural gas storage vessel with very high deliverability

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Salt Caverns

• Salt Caverns – In addition, cushion gas requirements are the lowest of all three storage types, with salt caverns only requiring about 33 percent of total gas capacity to be used as cushion gas. – Salt cavern storage are best suited for peak load storage – Salt caverns are typically much smaller than depleted gas reservoirs and aquifers, in fact underground salt caverns usually take up only one one-hundredth of the acreage taken up by a depleted gas reservoir – As such, salt caverns cannot hold the volume of gas necessary to meet base load storage requirements. However, deliverability from salt caverns is typically much higher than for either aquifers or depleted reservoirs – Therefore natural gas stored in a salt cavern may be more readily (and quickly) withdrawn, and caverns may be replenished with natural gas more quickly than in either of the other types of storage facilities – Moreover, salt caverns can readily begin flowing gas on as little as one hour's notice, which is useful in emergency situations or during unexpected short term demand surges – Salt caverns may also be replenished more quickly than other types of underground storage facilities Mauricio Prado – The University of Tulsa

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Liquified Natural Gas

• Liquified Natural Gas – Cooling natural gas to about -260°F at normal pressure results in the condensation of the gas into liquid form, known as Liquefied Natural Gas (LNG) – LNG can be very useful, particularly for the transportation of natural gas, since LNG takes up about one six hundredth the volume of gaseous natural gas – While LNG is reasonably costly to produce, advances in technology are reducing the costs associated with the liquification and regasification of LNG – Because it is easy to transport, LNG can serve to make economical those stranded natural gas deposits for which the construction of pipelines is uneconomical

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Natural Gas Storage

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