Overview Gas Processes

Design of Natural Gas Handling Equipment Course prepared for Offshore Oil and Gas Engineering program ENG 8976 by Majid A. Abdi, Ph.D., P.Eng. Faculty of Engineering and Applied Science Memorial University of Newfoundland (MUN) Winter 2004 1

Schedule and Evaluation Breakdown • Instructional hours per week: 3 lecture hours; • Midterm exam: March 1st, 2004; • Evaluation: – Assignments: 10% – Midterm: 25% – projects (term papers): 15% – Final: 50%

2

Course Outline 1. 2. 3. 4.

Introduction Fluid Properties Inlet separator design Prevention of hydrate formation and dehydration of natural gas 5. Natural gas dew point control and liquid recovery 6. Natural gas transmissions systems 7. Natural Gas Compression 8. Natural gas measurement* 9. Heat exchange equipment* 10. Overview of natural gas sweetening processes* 11. Natural gas transportation* *Optional sections; will be covered only if time allows 3

References 1. Beggs H.D., Gas Production Operation, OGCI publications, 1985, ISBN: 0-93097206-6 2. Kumar S., Gas Production Engineering, Gulf Publishing, 1987, ISBN: 0-87201-577-7 3. Rojey A., Jaffret C., Natural Gas Production Processing Transport, Editions Technip; (1997), ISBN: 2710806932 4. Manning F. and Thompson R., “Oil Field Processing of Petroleum, Volume 1: Natural Gas”, Pennwell Publishing, 1991, ISBN:0-87814-343-2 5. 11th Edition GPSA Engineering Data Book, FPS and SI Versions, 1998, by Gas Processors Suppliers Association 6. Arnold K. and Stewart M., Surface Production Operations; Volume 2; Design of Gas-Handling Facilities, 2nd Edition, 1999, Butterworth-Heinemann, ISBN: 0-88415822-5 7. Kohl A., Nielsen R., “Gas Purification”, 5th Edition, Pennwell, 1997, ISBN 0-88415220-0 8. Mohitpour M., Golshan H., and Murray A. "Pipeline Design & Construction, A Practical Approach", 2nd edition, ASME Press, 2003, ISBN 0-7918-0156-X 9. Manning F. and Thompson R., Oil Field Processing of Petroleum, Volume 1: Crude, Pennwell Publishing, 1991, ISBN: 0-87814-354-8 10. Arnold K. and Stewart M., Surface Production Operations; Volume 1; Design of oil Handling Facilities, 2nd Edition, 1999, Butterworth-Heinemann ISBN: 0-88415-821-7 11. Skinner, D.R., Introduction to petroleum production: well site facilities, Gulf Publishing Co., 1981, ISBN: 0872017699 12. Brian Research and Engineering (BR&E) technical papers, 2002; see web site at: http://www.bre.com/technicalpapers/technicalpaper-home.asp 4 13. Instructor’s notes on personal field and design experiences

World Natural Gas Occurrence and Production - International Gas Statistics

• Natural gas is a major world energy source. • World natural gas reserves are estimated at 5893 TCF. • About 72 percent of the world’s natural gas reserves are found in the Middle East and the former Soviet Union. • Canada is a major exporter of natural gas. 5

Natural Gas Origin

• • • •

Biogenic methane Thermogenic methane Metamorphism Abiogenic methane

6

History of Natural Gas

• Dates back to thousands years ago • Persians and Indians used it for religious practices • Chinese used it to desalt sea water • British commercialized natural gas

7

Source:

BP

8

World Natural Gas Reserves (2002)

9 Source: BP

World Natural Gas Reserves (2002)

10 Source: BP

World Natural Gas Production (2002)

11 Source: BP

World Natural Gas Production (2002)

12 Source: BP

World Natural Gas Consumption (2002)

13

World Natural Gas Consumption (2002)

14

Source : BP

15

Global Stranded Gas Reserves

16

North American Natural Gas Reserves (2001)

17

Canadian natural gas production/demand by region (2001)

18

Canadian Natural Gas

19

Canadian Natural Gas (2001)

20

Natural Gas Value Chain

21

Natural Gas Processing

22

Gas Processing Facility Block Diagram Sulphur Sales

Sulphur Production Natural Gas Well Gas Heating

High Pressure Separation

Controlled Release of emission gases to Atmosphere

Acid Gas Management Systems

Acid Gas Removal

Water Vapour Removal Dehydration

NGL Recovery Dew Point Control (DPC)

Cooling Compression Stabilization

LPG Recovery (C3 & C4)

Intermittent solid removal

SALES GAS

Water handling Facilities

Propane and Butane Sales Condensate Sales Water disposal 23

FLUID PROPERTIES Characterization of Natural Gas and Its Products SPECTRUM OF PRODUCED HYDROCARBONS FLUID TYPE

TYPICAL GOR

STOCK-TANK LIQUID

BSTO/BRF

SCF/BSTO

OAPI

COLOR

>0.5

<2,000

<45

Very dark – black oil

<0.5

2,000-3,300

>40

Colored – dark brown

>0.35

3,300-50,000

50-60

Water white

Wet gas

-

>50,000

>50

colorless

Dry gas

-

-

-

colorless

Associated gas from: •Low Shrinkage crude (Low GOR) –Ordinary crude •High Shrinkage Oil (high GOR) – volatile oil Retrograde gas – gas condensate

24

Fluid Properties – Natural Gas Constituents Class Hydrocarbons

Components

Formula

Abbreviation

Typical composition (volume %)

Methane

CH4

C1

59.0-92.0

Ethane

C2H6

C2

3.0-10.0

Propane

C3H8

C3

1.0-15.0

i-Butane

iC4H10

iC4

0.3-2.5

n-Butane

nC4H10

nC4

0.3-7.5

i-Pentane

iC5H12

iC5

0.1-2.0

n-Pentane

nC5H12

nC5

0.1-2.0 1.0-3.0

-

C6+

Nitrogen

N2

N2

Helium

He

0.01-0.1

Argon

Ar

a few ppm

Hydrogen

H2

a few ppm

Oxygen

O2

a few ppm

Hydrogen sulfide

H2S

0.01-10.0

Carbon Dioxide

CO2

0.2-10.0

R-SH

10-1000ppm

Hexanes and heavier

Inert Gases

Acid gases Sulphur compouns

Mercaptans

R-S-R

1.0-10.0ppm

R-S-S-R

1.0-10.0ppm

Free water or brine

H2O

variable

Corrosion inhibitors

-

variable

Methanol and glycol

CH3OH(MeOH), EG, etc.

variable

Sulfides Disulfides

Water vapour/Liquid slugs

Solids

0.2-5.0

Millscale or rust

-

variable

Reservoir fines and iron sulfide

FeS

variable

25

Fluid Properties – Natural Gas physical properties • • • • • • • • •

PVT behavior and equations of state Molecular weight Density and specific gravity Critical pressures and temperatures Gas compressibility factor Viscosity Specific heat (heat capacity) Heating value (Wobbe number/index) Thermal conductivity 26

Fluid Properties – Equations of State • • • •

Behavior of ideal gas Behavior of a real (non-ideal) gas Compressibility factor approach Important equations of state 9 Van der Waals 9 Benedict-Webb-Rubin (BWR) 9 Saove-Redlich-Kwang (SRK) 9 Peng-Robinson (PR) 9 Virial 27

Principal Equation of States

28

Fluid Properties – Molecular Weight – Mole concept Weight of a mole of any substance Different units in Imperial, SI and CGS systems Moles = Weight of a gas component divided by its molecular weight Average molecular weight =

MW = ∑[yN .(MW ) N ] 29

Fluid Properties – Density and Specific Gravity • Density = mass of a unit volume (lb/ft3 or kg/m3) • S = MW/29 (for gases)

( MW ) P ρ g = 0 .093 TZ

or

SP ρ g = 2 .7 TZ

• S.G.= density of liquids/density of pure water @ 60oF •

o

API =141.5/S.G. -131.5 (for liquid hydrocarbons such as crude oil) 30

Fluid Properties – Critical Pressures and Temperatures • Critical temperature= the maximum temperature at which the component can exist as a liquid • Critical pressure= vapour pressure of a substance at its critical temperature • Beyond critical temperature and pressure there is no distinction between a liquid and a gas phase PPC = Σ yNPCN and

TPC = Σ yNTCN

PPC = 709.604 – 58.718 S

PCN and TCN from Figure 23-2 GPSA

Thomas et al. equation

TPC = 170.491 + 307.344 S 31

Physical Property Tables

32

Physical Property Tables

33

Fluid Properties – Gas Compressibility Factor • • •

Standing-Katz compressibility charts (Figures 23-3, 23-4, and 23-5 GPSA) Brown-Katz-Oberfell-Alden charts (Figures 23-7, 23-8, and 239 GPSA) Acid gas content consideration by Wichert-Aziz correction factors ' TPC = TPC − ε

•

and

' P T ' PC PC PPC = TPC + Bε (1 − B)

ε from Figure 23-10 GPSA Compressibility from equations of state

34

Compressibility charts

Standing-Katz compressibility charts

Brown-Katz-Oberfell-Alden Z charts

35

Fluid Properties – Gas Viscosity • •

Carr et al. correlation (Fig. 23-32 and 23-33 GPSA) Viscosity of gas mixture from single component data: n

µ1 g =

∑µ N =1

1 gN

n

∑y N =1

•

y N MW N0.5

N

MW N0.5

Lee et al. for natural gas: 10 −4 (9.4 + 0.02 MW )T 1.5 209 + 19 MW + T X = 3.5 + 986 / T + 0.01MW and y = 2.4 − 0.2 X

µ g = K exp( Xρ gy ) where , K =

• •

GPSA charts – Fig.s 23-30 through 23-38 Dean and Stiel method ξ = 5.4402

(∑

1/ 6 5/9 TPC −5 [ ] ; for T > 1 . 5 , ξµ = 166 . 8 ( 10 ) 0 . 1338 T − 0 . 0932 , g Pr Pr 2/3 y N MW N )1 / 2 PPC

and for TPr ≤ 1 .5, ξµ g = 34 .0 (10 − 5 )TPr8 / 9 36

Viscosity Charts

37

Fluid Properties – Specific Heat • •

Definition: amount of heat required to raise the temperature of a unit mass of a substance through unity Cp and Cv and their relationships (Maxwell’s equation) ( ∂ P / ∂ T ) v2 C p − C v = −T (∂P / ∂v )T

•

•

Cp determination

for ideal gases C p − C v = R

– Hankinson’s gravity

C op = A + B.T + C.S + D.S2 + E(T.S) + F.T2

– Kay’s mixing rule

o C = ∑ y N C pN o p

n

N =1

Cp of natural gas mixture, pressure corrections (GPSA Figure 13-6 and Kumar’s Book – Table 3-3, Figures 3-17 and 3-19) 38

Heat Capacity Data

39

Fluid Properties – Heating Value/Wobbe Index •

• •

Definitions: – Gross Heating Value (GHV) or Higher Heating Value (HHV):Total energy transferred as heat in an ideal combustion reaction at a standard temperature and pressure in which all water formed appears as liquid – Net Heating Value (NHV) or Lower Heating Value (LHV):Total energy transferred as heat in an ideal combustion reaction at a standard temperature and pressure in which all water formed appears as vapour Heating value determination: Hv = Σ yNHvN Wobbe Index: WO=HHV /S1/2

40

Fluid Properties – Thermal conductivity •

• • •

Significance of thermal conductivity – Heat transfer calculations and heat exchanger (line heater, shell and tube, air cooler, etc.) design Determination of thermal conductivity – gas and liquid (GPSA Fig.s 23-40 through 23-45) Lenoir et al. pressure corrections Gas mixture thermal conductivity

km =

∑ ( yN k N . ∑ ( yN .

3

3

MWN )

MWN ) 41

Thermal conductivity Charts

42

Thermal conductivity Charts (cont.)

43

Phase Behavior - Fundamentals • • • •

Single component fluid Two component fluid Multi-component fluid Phase diagrams (envelopes) – – – –

Pressure-Temperature-Volume (PVT) Pressure-Temperature (PT) Pressure composition Composition-composition

• Phase rule N=C-P+2

44

Phase Behavior – Single Component Systems g

f

• Phase Equilibrium – gas-liquid – gas-solid – Liquid-solid • Triple point • Critical point

C

D

d

b c

a

e

Dense Fluid regionsupercritical fluid

h

B

A

45

Phase Behavior: Two-Component Systems Two component phase envelop

Cricondenbar C l g

Pressure Va of po pu ur re pre A ss ur e Bu bb le -P oi nt Li ne

PC

a

b

k j

d

h

Cricondentherm

• Concept of phase envelope • Equilibrium lines – Bubble point – Dew point • Critical point • Cricondentherm • Cricondenbar • Rertrograde phase change

e

’d ne i p v a nt L i re % u o s es 90 -P r p w ur e o p D Va ure B f of p

Temperature

TC

46

Phase Behavior: Multi-Component Systems Oil reservoir

A

C

B

et G as

C’

D’

E’ Cricondentherm

A’

W

Two-Phase Region (Gas+Liquid)

B’

E

D Dry Gas

C

Pressure

• Full wellstream • Source of phase diagrams • Quantitative phase behavior • Phase behavior in separators

Gas reservoir

Condensate reservoir

Temperature

47

Phase Behavior: Vapour-Liquid Equilibria •

Thermodynamic criteria for equilibriumequality of fugacities: fN,v= fN,l

•

Equilibrium ratio (K values): K=yN / xN

•

Equilibrium calculations – Equilibrium flash: VN =

K N FN 1 /(V / L) + K N

– Bubble point: ΣyN =Σ zN . KN = 1.0 Σ zN . KN > 1.0 guarantees vapour is present – Dew point: ΣxN =Σ zN / KN = 1.0 Σ zN / KN > 1.0 guarantees liquid is present

V, yN F, zN

L, xN A gas-liquid flash separator

48

Phase Behavior: Water Hydrocarbon Systems • •

•

Water and hydrocarbons are insoluble in liquid phase Problems with water saturated gas – Excessive pressure drop – Plugging due to ice and hydrate formation – Sever corrosion in acid and sour gas lines Water content of natural gas – McKetta and Wehe charts: Fig. 20-3, GPSA – Robinson et al. correlation for sour gases: Fig.s 20-10 and 2011, GPSA – Campbell charts: W = yhc Whc + yCO2 WCO2 + yH2S WH2S and Fig.s 20-8 and 20-9, GPSA) – Equation of state methods; SRK, PR and commercial process simulators (e.g. HYSYS, ASPEN, PROSIM, PROII, AMSIM, AQUASIM, SSI, DESIGNII, PROCESS, etc.) 49

Phase Behavior: Water Hydrocarbon Systems– Natural Gas Hydrates • •

Gas hydrate - pipeline trouble maker or ? Prediction of hydrate formation conditions – Katz Gas gravity – Wilson-Carson-Katz equilibriumconstant method – Baillie and Wichert method – Equation of state methods

•

Comparison of techniques to predict hydrate formation conditions

50

Water Hydrocarbon Systems: Overall Phase Behavior of Natural Gas- Hydrates Systems A. Normal Case

B. High Water Content

Temperature

Lhc+Lw+G+H

Lhc+Lw+G

G

Hy d Ph roca a En se rbon vel op e

G

Pressure

Lhc+G

Hy d Ph roca a En se rbon vel op e

Lhc+Lw+G

Wa De ter cC w-po urv int e

Lhc+Lw+G+H

Hy Fo drate Cu rmat rve ion

Pressure

A

Lw+G

Wat e Dew r Cur point ve

Hydrate Formation Curve

Lw+G

Temperature

51

Phase Behavior: Carbon Dioxide Frost Point • Significance of CO2 freezing- design of turbo-expansion facilities and cryogenic NGL recovery systems • CO2-methane equilibrium (Liquid-solid-vapour systems) (see Ref.1, also Fig.s 25-5 and 25-6 of GPSA data book) • Natural gas-CO2 systems (see Ref. 1) • Predicting CO2 formation conditions (GPSA charts vs. process simulators) 52

Natural Gas Properties/Phase Behavior and Scope of Natural Gas Field Processing • Process objectives – Transportable gas – Salable gas – Maximized condensate (NGL) production • Gas type and source – Gas-well gas – Associated gas – Gas condensate • Location and size of the field – Remoteness – Climate – size 53

Scope of Natural Gas Field Processing: Process objectives • Transportable gas – Hydrate formation – Corrosion – Excessive pressure drop (two-phase flow) – Compression requirement (dense phase flow) • Salable gas – Sales quality-pipe line spec. (see Fig. 2-4, GPSA) – Heating value-inert gas and condensate recovery • Maximized condensate (NGL) production – Maximizing crude production – Retrograde condensate gas processing – Inherent value of NGL 54

Scope of Natural Gas Field Processing: Type and Source of Natural Gas 1.

Gas-well gas – Wet or dry – Lean or rich – Sour or sweet

2.

Associated gas – Enhanced oil recovery (EOR) – Enhancement crude production

3.

Gas condensate – Pressure maintenance – Gas cycling operations 55

Scope of Natural Gas Field Processing: Filed Location, Size, and Operation • Remoteness – Offshore vs. onshore (land) reservoirs – Platform design – Floating gas processing (a new concept) • Climate – Design consideration for harsh environment – Cold vs. warm – Dry vs. humid • Size – Reservoir capacity – Production rate: small vs. large • Gas handling facilities operations 56

GAS AND LIQUID SEPARATION • Purpose, principles and terminology • Separation equipment- common components • Types of separators • Separation principles • Separator design • Factors affecting separation • Operational Problems 57

Gas and Liquid Separation: Separation Equipment- Major Parts

A - Primary Separation B - Gravity Settling C - Coalescing D - Liquid Collecting

58

Gas and Liquid Separation - Types of Separators • • • • •

Gravity (vertical vs. horizontal) Centrifugal Filter coalescing Impingement Comparison of separators – advantages vs. disadvantages

59

Gas and Liquid Separation: Separation Equipment- vertical separator

Source: Natco

60

Gas and Liquid Separation: Separation Equipment- Horizontal separators

61

Gas and Liquid Separation: Separation Equipment, Two-Barrel (Double-Tube) horizontal separator

62

Gas and Liquid Separation: Separation Equipment- horizontal filter separator Filter elements

63

Gas and Liquid Separation: Separation Equipment- mist eliminator arrangement

64

Gas and Liquid Separation: Separation EquipmentVane (radial/axial) mist extractor arrangement B C

A

Downcomer

J=ρg .Vt2 = 20 lb/(ft.sec2)

D NatcoTM radial vanes

Vertical Radial Flow (VRF) separator

65

Gas and Liquid Separation: Separation Equipment- Centrifugal separator

66

Gas and Liquid Separation: Separation Equipment- Swirl/cyclonic separators

Porta-Test Whirlyscrub ITM

Source: Natco

67

Gas and Liquid Separation –Separation principles FD

Vt =

Vt2 = C D Aρ[ ] 2g

Drag force

1 . 78 × 10 − 6 ( ∆ S .G .) d m2

µ

Stock’s termonal velocity for:

Re < 1.0

Re for actual natural gas and crude operations are much larger than 1.0, therefore the following equations should be iteratively used to calculate the terminal velocity and drag coefficient:

ρ l − ρ g d m 1/ 2 V t = 0 . 0119 [( ) ] ρg CD CD =

24 3 + + 0 .34 1/ 2 Re Re 68

Gas and Liquid Separation –Separation principles: Terminal Velocity/Residence Time calculations

•

•

Terminal velocity iterative calculations: ρl − ρg ) d m ]1 / 2 ρg

1.

Start calculating CD using:

V t = 0 . 0204 [(

2.

Calculate Re as:

ρg dmVt Re = 0.0049 µ

3.

Calculate new values for CD :

CD =

4.

Calculate new values for CD :

ρ l − ρ g d m 1/ 2 V t = 0 . 0119 [( ) ] ρg CD

5.

Go to step 2 and iterate until CD,new – CD,old ≤ 0.001

24 3 + + 0 . 34 Re Re 1 / 2

Residence time definition: Effective vessel volume/flow rate or:

t = V /Q 69

Gas and Liquid Separation – Separator Design

• Gas capacity • Liquid capacity • Gas Capacity Calculations: Souders-Brown’s Technique

• Vessel design considerations • Separator design using manufacturers separator performance charts • Computer based techniques Computational Fluid Dynamics (CFD), etc. 70

Gas and Liquid Separation – Sizing Equations •

Horizontal separator –

Gas Capacity: dL eff

 TZQ g = 420   P

  ρ g       ρ l − ρ g

 ρ g  TZQg   Or: dLeff = 42 K   , where, K =  ρ − ρ  l g  P  tQ 2 – Liquid Capacity: d Leff = r l 0 .7 –

•

– –

1/ 2

1/ 2

from Fig. 4.10 Ref.8

1/ 2

 TZQ g   ρ g  C D  2  Gas capacity: d = 5,040      P ρ ρ d − g  m    l   TZQ   g Or: d 2 = 420 K , where K is defined as above and found from Fig. 4.10 Ref. 8    P  Liquid capacity:

d 2h = –

  C D     

  

Seam to seam length: Lss = Leff + d/12 for gas capacity and Lss = 4/3 Leff for liquid capacity

Vertical Separators –

 CD  d  m

t r Ql 0 .12

Seam-to-seam length:

Lss =

h +76 h + d + 40 ;........or......Lss = 12 12

71

Gas and Liquid Separation: Sizing EquationsSouders-Brown Technique Terminal Velocity Equation

ρ l − ρ g d m 1/ 2 ) ] Vt = 0 .0119 [( ρg CD

Vt = K SB

ρl − ρ g ρg

Souders-Brown Equation API Spec. 12 J (1989) Recommendations for KSB values Separator type

Vertical

Horizontal

API Recom’d. KSB, (ft/sec.)

Most commonly used KSBValue (ft/sec.)

5

0.12-0.24

0.12 without and 0.2 with mist extractor

10

0.18-0.35

0.18 without and 0.3 with mist extractor

10

0.40-0.50

0.38 with mist extractor

Other lengths

0.4-0.5(L/10)0.565

-

Height, H or Length, L (ft)

72

Gas and Liquid Separation: Vessel design considerations

• • • • • • •

Liquid residence time: 2-4 min Liquid-gas interface (minimum diameter/height): 6 ft. vertical height; 26 in. horizontal diameter Gas specification: 0.1 gal/MMscf Liquid re-entrainment: API Spec. 12J Pipe connections: Fabrication cost Optimum length to diameter (L/D) or aspect ratio

API Spec. 12J (1989) (1989 Oil gravity oAPI

API recom’nd Liquid retention time (min)

Above 35

1

20-30

1 to 2

10-20

2 to 4

73

Gas and Liquid Separation: Separator Designmanufacturers charts

Source: Natco

74

Gas and Liquid Separation: Separator DesignCFD modelling

75

Gas and Liquid Separation: Factors Affecting Yaw Separators Performance

• • • • • • • • •

Pitch

Roll

Operating and design pressure and temperature Fluid composition and properties (density, Z-factor, etc.) Fluid (gas and liquid) flow rates Degree of separation Two vs. three phase Gas vs. oil - sand and solids? Surging/slugging tendencies Foaming and Corrosive tendencies Offshore floating vs. land base static facilities

Sway

Surge Heave

Motion

Linear motion Surge

Single point anchored tanker

Sway

◘

Semisubmersibles Tension-leg platforms

◘

◘

Guyed tower platforms

◘

◘

Articulated tower

◘

◘

Angular motion Heave

Roll

Pitch

◘

◘

◘

◘

◘

◘

Yaw

76

Gas and Liquid Separation: Operations • Potential Problems – Foaming – Fouling – • Solid/sand deposition • Hydrate, paraffin, wax – Corrosion – Liquid carryover and gas blowby – Flow variations • Maintenance • Troubleshooting 77

Gas and Liquid Separation: OperationsTroubleshooting 1. Low liquid level 2. High liquid level 3. Low pressure in separator 4. High pressure in separator 5. All the oil going out gas line 6. Mist going out gas line 7. Free gas going out oil valve 8. Gas going out water valve on three-phase 9. Too much gas going to tank with the oil 10. Condensate and water not separating in 3-phase 11. Diaphragm operated dump valve not working 78

NATURAL GAS DEHYDRATION • • • •

Introduction- purpose of gas dehydration Pipeline specification Hydrate prevention Methods of dehydration – Absorption dehydration using glycol – Solid bed adsorption – Expansion refrigeration (LTX units)

• Design techniques • Operations of dehydration facilities 79

Natural Gas Dehydration- Hydrate Prevention

• Line heating and Low Temperature Exchange Units (LTX • Inhibition by additives – Types and selection of additives – Inhibitor requirements – Prediction of inhibitor requirements – Injection techniques – Operations and troubleshooting 80

Natural Gas DehydrationHydrate Prevention

Typical Glycol injection system

81

Natural Gas Dehydration- Hydrate Prevention

• Inhibition by additives – Types and selection of additives – Process consideration – Injection techniques – Prediction of inhibitor requirements – Operations and troubleshooting

82

Natural Gas Dehydration- Hydrate Prevention: Inhibitor Requirements

• Inhibition by additives EG DEG – Types(dand selection )(MW )(100) of additives W= 4000 4000 KH – Process (d )(consideration MW ) + K H 62 106 MW – Injection techniques – Prediction of inhibitor requirements

Methanol 2335 32

• Hammerschmidt’s equation • Computer simulation

– Operations and troubleshooting 83

Natural Gas Dehydration- Hydrate Prevention: Operations and Troubleshooting

• Operations – Vapour losses – Corrosion – Glycol losses – Glycol-water-oil separation

• Troubleshooting – Preventing freeze-offs – Improving Glycol-Condensate Separation 84

Natural Gas Dehydration- Glycol Absorption

• Advantages over other methods of dehydration: – Solid desiccant – Expansion refrigeration (LTS or LTX units)

• • • •

Choice of glycol (EG and DEG vs. TEG) Process description and elements Design methods Process operations 85

Natural Gas Dehydration- Glycol Absorption Source: Natco

A typical glycol absorption process

86

Natural Gas Dehydration- Glycol Absorption Process Elements: 1. 2. 3. 4. 5. 6. 7. 8. 9.

Natco bubble cap

Inlet scrubber Absorber (glycol contactor) Flash tank Filters Glycol pump Surge tank Heat exchangers Regeneration system (tower and reboiler) Instrumentation 87





Natural Gas Dehydration- Glycol Absorption: Design Guidelines • Required information – – – –

Inlet gas flow rate, T and P and composition Required water dew point Available utilities Safety/environmental regulations

• Required TEG reconcentration • Process flow sheeting (M&EB) • Equipment sizing

Equipment Specification Tables from Natco 90

Natural Gas Dehydration- Glycol Absorption: Design Guidelines

Equipment sizing: • Contactor – Height (2 to 3 theoretical stages or GPSA Figures 20-53 to 20-58) – Diameter (Sauders-Brown)

•

Pump (70-80% mechanical efficiency Pump BHP=(0.000012) (gph) (psig)

91

Natural Gas Dehydration- Glycol Absorption: Design Guidelines Regeneration package • Flash Tank • Stripping column – Three theoretical stages – Diameter: 9.gpm0.5

•

Reboiler – Duty: 1500.gph – Temp.: 370-390oF – Firetube flux: 60008000 Btu/hr.ft2

92

Natural Gas Dehydration- Glycol Absorption: Design Guidelines

• Heat Exchangers – Reflux condenser – Lean-rich glycol HX – Lean glycol cooler

93

Natural Gas Dehydration- Glycol Absorption: Operations Contactor • Inlet gas flow rate • Inlet gas T and P Process location • Len TEG T and Inlet gas concentration TEG to contactor TEG to flash tank • TEG flow rate TEG to filters • Contactor T TEG to stripping column Top of stripping column Reboiler TEG entering pump

Tempearture (oF) 80-100 5-15 warmer than inlet gas 100-150 (prefer 150) 100-150 (prefer 150) 300-350 210 380-400 (prefer 380) <200 (pefer 180) 94

Natural Gas Dehydration- Glycol Absorption: Operations

• Regenerator – Reboiler T – Stripping gas – Column T

Drizo® Process

95


• Glycol care – Oxygen – Thermal decomposition – Low pH – Salt contamination – Liquid HC – Sludge accumulation – Foaming 96


• Glycol pump • Sour gas • Startup/shutdown

97


Preventive maintenance – Daily – Weekly – Monthly – Annual inspections

98

Natural Gas Dehydration- Glycol Absorption: Troubleshooting • High exit gas dew-point • High glycol loss (should be < 0.1 gal/MMscf) – – – –

Loss from contactor Loss from stripping column Loss from separator Leaks and spills

• Glycol contamination • Poor glycol regeneration

• Low glycol circulation • High pressure drop across contactor • High stripping column temperature • High reboiler pressure • Firetube fouling/ hotspots/ burnout • Low reboiler temperature • Flash separator failure 99

Natural Gas Dehydration- Solid desiccants

Example Solid Desiccant Dehydrator Twin Tower System (Source: GPSA) 100

Natural Gas Dehydration- Solid desiccants

Natco’s solid desiccant beds

101

Natural Gas Dehydration- Solid desiccants: Design • •

Allowable gas superficial velocity ∆P Pressure drop - vessel diameter: Ergun’s eq. = B µV + C ρ V 2 Particle type

B

C

1/8” bead

0.056

0.0000889

1/8” extrudate

0.0722

0.000124

1/16” bead

0.152

0.000136

1/16” extrudate

0.238

0.000210

L

Allowable Velocity for Mole Sieve Dehydrator

• Cycle time (6-8 hours) • Bed length: Saturation Zone (LS) and Mass Transfer Zone heights (LMTZ)

Ss =

4S s Wr and Ls = 0.13(Css )(CT ) πD 2 (bulk density)

102

Natural Gas Dehydration- Solid desiccants: Design (cont.)

• Length of mass transfer zone LMTZ = (V/35)0.3 (Z) • Bed regeneration – Heat duty – Regeneration gas rate

• General comments on dsing 103

Natural Gas Dehydration- Solid desiccants: Operations

• • • • •

Desiccant installation Startup Switching Operating data Energy conservation

104

Natural Gas Dehydration- Solid desiccants: Troubleshooting

• Proper design-Design considerations • Bed contamination • High Dew point • Premature Breakthrough

105

Natural Gas Dehydration- Refrigeration and Membrane

Manufacturer selection guide (source: Natco)

A typical JT unit for water and NGL removal (source: Natco)

Membrane systems (Source: Air Products)

106

Natural Gas Dehydration- Process Selection

• Dehydration methods advantages and disadvantages – TEG (glycol dehydration) – Solid desiccants – Low temperature – Membranes

• Selection recommendations

107

NATURAL GAS LIQUID RECOVERY • • • •

Why NGL recovery? NGL components and specifications Introduction to low temperature processes Processing objectives – Transportable gas – Sales gas – Maximum NGL recovery

• Value of NGL • Liquid Recovery Porcesses 108

Natural Gas Liquid Recovery- Processes

Interchange JT and Expander

Refrigeration Gas-Gas HX

Liquid

C

C’’ C’

B

A Expander JT

Hydr o Phas carbon e Enve lope

Refrigeration JT-Valve expansion (LTS) JT-Turbine Expansion Oil absorption Solid bed adsorption

Pressure

• • • • •

Gas

Temperature

109

Natural Gas Liquid Recovery- Processes: Joule-Thompson (JT) Valve Expansion Refrigeration

Liquid

Gas-Gas HX

C B

C’’ C’

A Expander JT

Hyd ro Pha carbon s Env e elop e

Pressure


Gas

Temperature

A simplified JT Expansion Process

110

Natural Gas Liquid Recovery- Processes: LTS Units

111

Natural Gas Liquid Recovery- Processes: LTS Units

112

Natural Gas Liquid Recovery- Processes: Refrigeration

113

Natural Gas Liquid Recovery- Processes: Refrigeration

114

Natural Gas Liquid Recovery- Processes: Oil absorption

Flow Diagram of a Refrigerated Lean Oil Absorption Process

115

Natural Gas Liquid Recovery- Processes: JT Turbine Expansion Refrigeration

Liquid

Gas-Gas HX

C B

A Expander JT

C’’ C’

Hyd ro Pha carbon s Env e elop e

Pressure


Gas

Temperature

A Simplified Turbo Expansion Flow Diagram

116

Natural Gas Liquid Recovery- Processes: JT Turbine Expansion

Conventional Turbo-expansion System 117


Residue Recycle (RR) Turbo-expansion Process 118


119


120


121

Natural Gas Liquid Recovery- Processes: Mixed Refrigerant

122

Natural Gas Liquid Recovery- Processes: Solid Bed Adsorption

Solid Bed Adsorption Dew Point Control Units

123

Natural Gas Liquid Recovery- Process Selection • NGL content of the gas – Low: expander process – High: external refrigeration

• Inlet gas pressure – High: LTS – Low: Turbine expansion or refrigeration

• Gas flow rate – Low: simple valve JT unit, solid adsorption or membranes – Large: more complex plants

• Location (offshore, onshore, or remote areas) 124

Natural Gas Liquid Recovery - Process Design • Process flowsheeting/simulation – EOSs (SRK, PR, etc.) – Software packages (BR&E PROSIM®, Hyprotech HYSYS®, Aspen®, Chemshire Design II®, SSI PROCESS® and PRO/II® etc.)

• Equipment selection – – – –

HXs Towers Turboexpanders Pumping and storage 125

Natural Gas Liquid Recovery – Equipment Selection: Heat Exchangers

Basic Components of a Three Stream Counterflow Brazed Aluminum Heat Exchanger

Typical Fin Arrangements for Gas/Gas 126 Exchanger

Natural Gas Liquid Recovery – Equipment Selection: Towers, Pumps, and Storage

127

Natural Gas Liquid Recovery – Refrigeration Cycle Simple Cycle

•

Process flow diagram

•

Vapour compression P-H diagram 1. Expansion 2. Evaporation 3. Compression 4. Condensation

128

Natural Gas Liquid Recovery – Refrigeration Cycle

129

Natural Gas Liquid Recovery – Refrigeration Cycle: Single, vs Multistage Systems

130

Natural Gas Liquid Recovery – Refrigeration Cycle: Single, vs Multistage Systems

131

Natural Gas Liquid Recovery – Refrigeration Cycle: Refrigerant Cascading

132

133

Natural Gas Liquid Recovery – Design and Operating considerations • Oil removal • Liquid surge and storage • Vacuum systems (air leaks

and corrosion)

•Vacuum considerations

134

Natural Gas Liquid Recovery – Design and Operating considerations

•

Material of construction 9no copper in presence of ammonia and sulfur compounds 9Steel is preferred (CS down to -20oF) 9Aluminum alloy and SS for very low Ts 9ANSI B31.3 and B31.5 design codes

•

Refrigeration purity 9Lube oil 9Light and heavy ends 9Process fluid leak 135 9Air leak and humidity (use drier or methanol wash/purge)

Natural Gas Liquid Recovery – Refrigeration Compressors Compressor types

• Centrifugal (>450 HP) • Reciprocating (higher efficiency, multistage) • Screw (high compression ratios up to 10, less noise) • Rotary (low capacity)

136

Natural Gas Liquid Recovery – Mixed refrigerant

137

Natural Gas Liquid Recovery – Refrigeration Chillers

• Kettle type Allowable refrigerant load in lb/hr per ft3 vapor space =

( S .F .)( ρ V )( 3980 ) ( 0 .869 )

σ ρ L − ρV

• Plate fin

138

Natural Gas Liquid Recovery – Refrigeration Control System • Level 9 displacer-type 9 internal float 9 differential pressure

• Pressure 9 Compressor suction and discharge

• Temperature 9 Chiller (by controlling compressor suction pressure) 9 Low ambient

139

Natural Gas Liquid Recovery – Refrigeration Operations and trouble shooting

• • • •

High Compressor Discharge Pressure High Process Temperature Inadequate Compressor Capacity Inadequate Refrigerant Flow to Economizer or Chiller

140

Overview Gas Processes

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