design for a wide range of operational flexibility
TRANSCRIPT
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
Principal Process Engineer
Staff Process Engineer
Staff Process Engineer
Staff Process Engineer
Staff Process Engineer
Principal 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
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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
Hale, S. 2008. Determination of Hydrocarbon Dew Point Using a Gas Chromatograph. Emerson Process Management.
Unexpected Retrograde Condensation
Two-Phase
Hale, S. 2008. Determination of Hydrocarbon Dew Point Using a Gas Chromatograph. Emerson Process Management.
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
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Design for Flexibility – Thermodynamics & Equipment
Design for Flexibility - Piping, Instrumentation & Controls
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▪ 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
Qualls, W., 2015. Operations Excellence Begins in Design
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
Estimated Travel (%)
Gai
nG
ain
Estimated Valve Travel (%)
Equal Percentage Valve Example
Highly Unstable Between 30 and 60% Valve Travel
Qualls, W., 2015. Operations Excellence Begins in Design
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
Estimated Travel (%)
Gai
nG
ain
Linear Valve Example
Estimated Valve Travel (%)
Inherent Stability Throughout Entire Valve Travel Range
Qualls, W., 2015. Operations Excellence Begins in Design
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
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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
Elliot, D., et al. 2005. Benefits of Integrating NGL Extraction & LNG Liquefaction Technology.
Study Results Comparing No HRU, Lean Reflux & Ethane Rich Reflux
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86
88
90
92
94
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100
102
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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
Elliot, D., et al. 2005. Benefits of Integrating NGL Extraction & LNG Liquefaction Technology.
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
Queensland Curtis LNG
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
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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
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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
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Darwin LNG
3.7 MTPA, 2006
Queensland Curtis LNG
8.5 MTPA, 2014 -2015Gladstone LNG
7.8 MTPA, 2015
Cold Nitrogen Rejection Unit
OCP Facilities With Cold NRU Designs
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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
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60
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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