design for a wide range of operational flexibility

Design For a Wide Range of Operational Flexibility

©2019 ConocoPhillips CompanyOptimized Cascade® is a registered trademark of ConocoPhillips Company

in the United States and certain countries

ConocoPhillips LNG Engineering & Operations

2

Manager

Filippo Meacci

LNG Conceptual Process

Engineering SupervisorLNG Operations Supervisor

LNG Process Engr. &

Tech. Support SupervisorEngineering Fellow

Wes Qualls

Principal Process Engineer


Staff Process Engineer





Attilio Praderio

Staff Process EngineerStaff Process Engineer

Senior Process Engineer

Required – Key Process Design Information

▪ Plant Feed➢ Composition Characterization

• Lean• Average• Rich• High N2

• High CO2

➢ Pressure, Temperature, & Compositional Variations➢ Contaminates

▪ Ambient Conditions & Range➢ Low, Average & High Ambient Temperatures➢ Extreme Conditions➢ Air Recirculation ➢ Pollen, Insects, Dust & Other Debris

▪ Equipment Design Specifications & Margins➢ Piping➢ Compressors➢ Pumps➢ Exchangers➢ Columns➢ Separators

▪ Chemicals Import Specifications➢ Propane Refrigerant➢ Ethylene Refrigerant➢ Solvent Circulation (Import)➢ Heat Transfer Fluids

▪ Production Targets➢ Design & Margins➢ Rated Cases➢ Peak Ship Loading➢ Turndown➢ Reliability, Availability & Maintainability

▪ Product Specifications➢ LNG ➢ LPG Recovery Targets & Product Specs (If Applicable)➢ Condensate➢ Fuel Gas Export (If Applicable)➢ N2 Vent (For Further He Recovery)

▪ Emissions➢ Turbine - Dry Low NOx/DLN (If Applicable)➢ Turbine - Water Injection (If Applicable)➢ Compressor – Seal Gas ➢ N2 Vent (If Applicable)

Facilities Licensing the Optimized Cascade Process

4

Kenai LNG

1.5 MTPA, 1969

Corpus Christi LNG

13.5 MTPA, 2018

Atlantic LNG

14.8 MTPA, 1999-2005

Egypt LNG

7.2 MTPA, 2005

Darwin LNG

3.7 MTPA, 2006

Equatorial Guinea LNG

3.7 MTPA, 2007

Angola LNG

5.2 MTPA LNG, 2013

1.7 MTPA NGL

Queensland Curtis LNG

8.5 MTPA, 2014 -2015

Gladstone LNG

7.8 MTPA, 2015Wheatstone LNG

8.9 MTPA, 2017 -2018

Australia Pacific LNG

9.0 MTPA, 2015 - 2016

Sabine Pass LNG

22.5 MTPA, 2015 -2018

Feed Characterization

▪ Unexpected Two-Phase Flow (Multiple Locations Within Facility)➢Acid Gas Removal System Foaming

• Unexpected Liquid Ingress

• Change of Phase Within Absorber

➢Dehydration System Early Moisture Breakthrough• Channeling of Liquid Through Sieve or Down Vessel Walls

➢Sieve Fouling & Impingement Damage at Top• Coking During Regeneration

➢Unexpected Fired Equipment Burner/Combustor Fouling

▪ Waxing or Freezing & Associated Downtime to Defrost (Lost Production)➢Heavies Freezing Before Reaching Heavies Removal Unit

➢Incorrect Heavies Removal Unit Design and Operating Parameters

▪ Off Spec LNG Products

Potential Results From Improper Feed Characterization

Hale, S. 2008. Determination of Hydrocarbon Dew Point Using a Gas Chromatograph. Emerson Process Management

Feed Composition - Typical Phase Diagram

Two-Phase

Retrograde Condensation

Hale, S. 2008. Determination of Hydrocarbon Dew Point Using a Gas Chromatograph. Emerson Process Management.

Expected Operating Point & Equipment dP


Unexpected Retrograde Condensation

Two-Phase


Characterize Feed Compositions

▪ Lumping C5+ and/or C6+ components into a single component(s) can lead to dramatically different hydrocarbon dewpoint temperatures. Dewpointvariances of 30 deg. F (17 deg. C) and larger are not unusual.

▪ Lumping components often results in shifted phase envelopes, sometimes leading to hydrocarbon liquid formation in undesired locations within processing facilities.

▪ Diligence is recommended to characterize the feed composition in such a manner to provide accurate phase envelopes as well as frost predictions.

Involve Subject Matter Experts (SMEs) BEFORE Starting Design

Physical Properties Subject Matter Expert Involvement

▪ Selection of Physical Properties Methods for Various Facility Locations

▪ Experience with Feed Characterization Techniques for Mid-Range Boiling Components Applicable to LNG Facilities

➢ Different Techniques Than Typical Reservoir Characterization

▪ Experience with Selection of Industry Available Feed Pretreatment Technologies

▪ Experience with Frost Prediction

➢ Must Combine Feed Characterization Effort & Frost Prediction Effort

Operations Focus in Design

Operations Excellence Begins in Design

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▪ Design to Ensure Operation Over Entire Range of Conditions➢ Low, Average & High Ambient Temperatures (Including Air Recirculation & Extremes)

➢ Low, Average & High Pipeline Temperatures & Pressures

➢ Lean, Average, Rich, High CO2, High N2, and other Compositional Variances

➢ Ensure Controls Cover Full Range of Variation (Frequency & Magnitude)

➢ Strive for Optimal Efficiency at Average Design Conditions

▪ Design With Operations Focus➢ Plot Plan Review for Efficient Equipment Layout, Siting & Spacing & Loss Prevention

➢ Controls & Instrumentation Review of Initial Design

➢ Operations Review of Initial Design

• Startup

• Upsets (Trips, Liquid Carryover, Rapid Changes in Conditions)

• Best Practices (Including Lessons Learned)

Involve Subject Matter Experts (SMEs) THROUGHOUT Design

▪ Thermodynamics & Physical Properties SMEs Should Include or Ensure➢ Thorough Feed Characterization

➢ Correct Physical Properties Methods Utilized

➢ No Unexpected Retrograde Operation

➢ No Freezing at Any Location Within Process

➢ No High Skin Temperatures, Degradation, or Hydrocracking

▪ Equipment Design SMEs Should Include or Ensure➢ Sufficient Refrigeration Compressor Operating Margin

• From Surge & End of Curve

➢ Average Operating Points Near Best Efficiency

➢ Sufficient Pump NPSH

➢ Sufficient Piping Straight-Run Distance (All Equipment)

➢ Correct Separations Equipment Sizes & Internals Selection Over Full Range of Operation

➢ Sufficient Liquid Droplet & Vapor Bubble Disengagement

➢ No Excessive Pressure or Temperature Rates of Change

➢ Turndown Requirements Achieved

15

Design for Flexibility – Thermodynamics & Equipment

Design for Flexibility - Piping, Instrumentation & Controls

16

▪ Piping Hydraulics Design Should Include or Ensure➢ No Slug Flow (Particularly Riser Slugging on Turndown)

➢ No Potential for Rapid Vapor Expansion or Liquid Hammer

➢ Pressure Equalization Where Required

➢ Proper Nozzle Sizes• Velocity & Momentum

• Self Venting Where Necessary

➢ Sufficient Piping Straight-Run Distance for Vessels, Meters, Strainers, Etc.

➢ No Excessive Piping Velocities

▪ Controls & Instrumentation Design Should Include or Ensure➢ Review of all Design & Rated Cases for Sufficient Control Valve Pressure Profile

• Sufficient dP for all Bypass Controls Valves (Install Pinch Valves as Required)

➢ Sufficient Vessel Residence Time

➢ Proper Selection & Placement of Instrumentation

➢ Proper Valve Trim Selection

➢ No Two-Phase Flow Control Valves (If Possible)

➢ No Overreliance on DCS Control Algorithms

➢ Startup, Shutdown & Continued Operation at Turndown

“For process engineers, it is not always sufficient to think like a molecule. Sometimes, one must think as a slug.”

A Minimum Length of 10 Diameters of Straight Run Inlet Piping is Recommended

Where:

K = Empirical Sizing ConstantVmax = Max Terminal Velocity

va = Actual Volumetric Flow

VN = Inlet Nozzle Velocity

VO = Vapor Outlet Nozzle Velocity

A = Cross Sectional Area

DV = Inside Diameter of Vessel

DN = Inside Diameter of Inlet Nozzle

LAN = Height Above Inlet Nozzle

LBN = Height From HHLL to Btm of Nozzle

ρl = Density of Liquid

ρg = Density of Gas

ρm = Mixed Phase Density

Cm = Clearance to Mesh Pad

X = Nozzle OD to Mesh Pad Distance

LLLL = Low Low Liquid Level

LLL = Low Liquid Level

NLL = Normal Liquid Level - Range

HLL = High Liquid Level

HHLL = High High Liquid Level

V = Top Vent Tap

DP1 = Upper Differential Pressure Tap

DP2 = Lower Differential Pressure Tap

LT1/LT3 = Upper Level Transmitter Taps

LT2/LT4 = Lower Level Transmitter Taps

Vmax = K[(ρl-ρg)/ρg)]½

A = va/Vmax

DV = (4A/π)½

K = Experience Factor

Round Calculated DV Up to

Nearest 6" Increment

Example - Simple Vertical Separator

Qualls, W., 2015. Operations Excellence Begins in Design

Installed Valve Characteristic - Example

LV-16195 Installed Characteristic

6" MarkOne, 5:00Cv:355, Equal Percentage

0

10

20

30

40

50

60

70

80

90

100

0 10 20 30 40 50 60 70 80 90 100

Estimated Travel (%)

Flo

w (

%)

Flo

w (

%)

Estimated Valve Travel (%)

Typical Equal Percentage Valve Example


Resulting Installed Gain - Example

LV-16195 Installed Gain

6" MarkOne, 5.00Cv:355, Equal Percentage

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

11.0

0 10 20 30 40 50 60 70 80 90 100


Gai

nG

ain


Equal Percentage Valve Example

Highly Unstable Between 30 and 60% Valve Travel


Different Valve Selection – Greatly Improved Installed Gain Profile

LV-16195 Installed Gain

4" MarkOne, 2.25Cv:117, Linear

0.0

1.0

2.0

3.0

4.0

5.0

0 10 20 30 40 50 60 70 80 90 100


Gai

nG

ain

Linear Valve Example


Inherent Stability Throughout Entire Valve Travel Range


Heavies Removal

Fulcrum

Liquefaction Pressure Optimization

ConocoPhillips Confidential Information

22

For Plants With Heavies Removal Requirements, the Heavies Removal System is the Fulcrum Upon Which All Else is Based & Therefore the Key to Success.

Heavies Removal Design – Simplified Decision Chart

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Heavies Removal Design Options

No Heavies

Lean Gas Moderate Heavies

No Freezing Components

Significant Heavies

Freezing Components

Heavy Tail w/ No Intermediates

No LPG Recovery LPG Recovery

No HRU Solvent Circulation

Non-Refluxed HRC (BTU Control) Lean or Rich Reflux HRC

Rich Reflux HRC

Heavies Removal Options For A Wide Range of Feed Compositions

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▪ No Heavies Removal Option - Applicable When➢ LNG Product Will Not Exceed Maximum BTU Specifications ➢ No Freezing Will Occur Anywhere in the LNG Facility

▪ Heavies Removal Column With no Reflux - Applicable When➢ Required to Remove a Relatively Small Amount of LPG and NGL Components➢ No Freezing Components are Present

▪ Heavies Removal Column Lean Reflux – Applicable When ➢ Required to Remove Small to Moderate Amounts of LPG & NGL Components➢ Insufficient Intermediate Components are Available for Rich Reflux Option ➢ Freezing Components are Present ➢ Ethane Recovery is Required (Rare)

▪ Heavies Removal Column Rich Reflux – Applicable When ➢ Required to Remove Moderate to Significant Amounts of LPG & NGL Components➢ High LPG Recovery is Required➢ Sufficient Intermediate Compounds are Available for Reflux

▪ Heavies Removal Column Solvent Circulation – Applicable When➢ Lean Gas with a Heavy Hydrocarbon Tail and No Intermediates are Present➢ Heavy Hydrocarbon Tail Contains Freezing Components

Methane & Ethane Critical Locus

25

300

400

500

600

700

800

900

1000

-170 -140 -110 -80 -50 -20 10 40 70 100

Temperature, F

Press

ure, p

sia

Ethane

Methane

▪ Careful Addition of Some Higher Molecular Weight Components to Heavies Removal Column Reflux Can Increase Critical Pressure, Which Allows a Higher Operating Pressure.

▪ Operating the Heavies Removal Column at Higher Operating Pressures Conserves Refrigeration Duty Because the Column Overhead Stream is Easier to Condense at Higher Pressures.

Elliot, D., et al. 2005. Benefits of Integrating NGL Extraction & LNG Liquefaction Technology.

C1 & C2 Mixtures Result in Higher

Critical Pressures Than Either Pure

Component

Typical Gas Plant Demethanizer With Rich Reflux

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Inlet Gas

Liquid Product

Demethanizer

Reflux

System

FURTHER ENHANCEMENT

AS REQUIRED

LNGLNG

PLANT

-106 F120 F

2nd Column Concentrates C2 and/or Heavier to Use as Reflux for First Column


Study Results Comparing No HRU, Lean Reflux & Ethane Rich Reflux

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86

88

90

92

94

96

98

100

102

104

106

108

110

0 10 20 30 40 50 60 70 80 90 100

C3 Recovery, %

Rela

tiv

e S

pecif

ic P

ow

er, H

P/M

MS

cfd

Feed

e

Base Case, C5+ Removal

No-Reflux Scheme

Methane Reflux Scheme

DeC2 O verhead Reflux

Stand-alone


The Difference Between the Specific Power Requirement for Lean Reflux and Rich Reflux Increases as Propane Recovery Targets Increase.

No Heavies Removal Unit

OCP Facilities With No HRU

Kenai LNG

1.5 MTPA, 1969

Equatorial Guinea LNG

3.7 MTPA, 2007


8.5 MTPA, 2014 -2015

Gladstone LNG

7.8 MTPA, 2015

Australia Pacific LNG

9.0 MTPA, 2015 - 2016

Reservoir Gas – No HeaviesUpstream Gas Plant

Coal Seam Methane

Coal Seam Methane

Coal Seam Methane

Heavies Removal Column w/ Lean Reflux

OCP Facilities With Lean Reflux

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Corpus Christi LNG

13.5 MTPA, 2018

Atlantic LNG

14.8 MTPA, 1999-2005

Egypt LNG

7.2 MTPA, 2005

Sabine Pass LNG

22.5 MTPA, 2015 -2018

Reservoir Gas With Moderate Heavies

Reservoir Gas With Moderate Heavies

Pipeline Gas With Few Heavies

Pipeline Gas With Few Heavies

Heavies Removal Column w/ Rich Reflux

OCP Facilities With Rich Reflux

30

Angola LNG

5.2 MTPA LNG, 2013

1.7 MTPA NGL

Wheatstone LNG

8.9 MTPA, 2017 -2018Reservoir & Associated Gas - LPG & NGL Recovery

Reservoir Gas- No LPG Recovery

Heavies Removal Column w/ No Reflux

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Darwin LNG

3.7 MTPA, 2006

OCP Facilities With Non-Refluxed HRC

Reservoir Gas with Partial Upstream Condensate Removal

Nitrogen Rejection

Nitrogen Rejection Units

▪ A Nitrogen Rejection Unit (NRU) is Required When the N2 Concentration in the Feed Exceeds the Amount that can be Rejected to Fuel.

▪ NRUs Within LNG Facilities are Typically Auto-refrigeration Processes, Comprised of 2 to 3 Columns and 2 or More Multiple Pass Brazed Aluminum Heat Exchangers, Contained Within a Cold Box.

▪ Typical N2 Vent Purity Specifications are 1% or Less.

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NRU Options Within Optimized Cascade LNG Process

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▪ Warm NRU➢ High Efficiency

➢ No Dedicated Rotating Equipment for Feed or Product Streams Required• Third Column Bottoms Pump Optional

➢ Less Heat Integration With Main Liquefaction Facility• Ability to Bolt On at Later Date (Future N2 Case)

▪ Cold NRU➢ Higher Efficiency

➢ Higher Stability

➢ No Dedicated Rotating Equipment for Feed or Product Streams Required• Third Column Bottoms Pump Optional

➢ Faster Controls Response

➢ More Heat Integration With Main Facility• Rapid Startup Times

• Responds Quickly to Changes in Feed N2

➢ Option Available for All Stainless Steel Exchangers

▪ Refluxed Third Column➢ Less C1 in N2 Vent

Nitrogen Rejection Unit Design – Simplified Decision Chart

35

Nitrogen Rejection Unit Options

Little Nitrogen Moderate Nitrogen

Stable Concentration

Significant Nitrogen

Reject to Fuel

Warm or Cold NRU

Cold NRU

Variable Concentration

Cold NRU

Future Nitrogen Case

Warm NRU

Optional Refluxed Third NRU Column Designs Available for Both Warm And Cold NRUs for Improved Vent Purity Control

Warm Nitrogen Rejection Unit

OCP Facilities with Warm NRU Designs

36

Darwin LNG

3.7 MTPA, 2006


8.5 MTPA, 2014 -2015Gladstone LNG

7.8 MTPA, 2015

Cold Nitrogen Rejection Unit

OCP Facilities With Cold NRU Designs

37

Wheatstone LNG

8.9 MTPA, 2017 -2018Australia Pacific LNG

9.0 MTPA, 2015 - 2016

Closing Points

Equipment

Unit Ops

Technology

Unit Design Notes:✓ Piping✓ Instrumentation✓ Layout & Arrangement✓ Hazard Mitigations

Equipment Specification Overlays:✓ Process Design✓ Mechanical Design✓ Layout & Arrangement

Technology Instructions:✓ System Design Considerations

(e.g. Propane Quenching System)✓ Commissioning & Startup Considerations✓ Key Interface Guidance

✓ Fuel Gas System✓ BOG ✓ De-Frost Gas✓ Cold Blowdown System

✓ Unit Performance

✓ Equipment Performance

✓ Technology Performance

Work Process Management for Operational Success

Operational Configuration Turndown

Peak Rate 100 - 105%

Full Rate 80 -100%

1 GT offline 60 - 80%

Half Rate 30 - 60%

Idle / low rates 0 - 30%0

10

20

30

40

50

60

70

80

90

100

110

0 10 20 30 40 50 60 70 80 90 100 110

Effi

cie

ncy

, % o

f D

esi

gn

Flow, % of Design

Plant goes to 1/2 rate

Maximum Plant Availability & Turndown Flexibility

Most Operationally Flexible Design Approach

Feed GasTreatment

Storage

PropaneGT / Compressors

EthyleneGT / Compressors

MethaneGT / Compressors

Ethylene Cycle Methane Cycle

LPGs & NGL Plant Fuel

Vapor Return

Propane Cycle

50%

50%

50%50%

50%50%

▪ Optimized Cascade Options Cover the Widest Possible Feed Composition Range➢ Reservoir Gas (2nd Baseload Plant – Kenai LNG, 1969)

➢ Associated Gas

➢ Mixture of Reservoir and Associated Gas

➢ Coal Seam Methane Gas (Industry First)

➢ Common Carrier Pipeline Gas (Industry First)

▪ Optimized Cascade Provides Operational Flexibility (All Projects)➢ Meet & Exceed Design Production

➢ Meet & Exceed Design Thermal Efficiency

➢ Operate Over Full Operating Range Defined in Process Design Basis

➢ Achieve Highest Feed/Production Turndown & Turndown Efficiency in Industry

➢ Achieves Rapid Cool Downs & Startups

➢ Provides Stable Control Through All Operational Ranges

Conclusions

Discussion

design for a wide range of operational flexibility

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