Maximizing the Gas Processing Market by Combining NGL Recovery with LNG

MAXIMIZING THE GAS PROCESSING MARKET BY
COMBINING NGL RECOVERY WITH LNG
Dave Beck and Tim Miller

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Demonstration of the commercial
advantages and technical challenges
of producing LNG in the midstream
market.
Background on LNG
Coupling LNG product with NGL plants
Technical challenges & solutions
Design optimizations
Conclusion
INTRODUCTION

Abundance of Natural Gas is
enhancing the following markets
Natural Gas as a transportation fuel
 Marine
 Land
Natural Gas as a preferred fuel for power
generation / high horsepower
Expanded Natural Gas use in industrial
applications
LNG production allows for new market
accessibility
NATURAL GAS ENERGY

LNG is primarily made up of
methane with small amounts of
ethane and propane. As its name
indicates, it is in the liquid state.
Cooled to below -260o F
Occupies 1/600th the volume of gas
Stored at low pressures
Less of a pollutant fuel source
LNG BASICS
Pollutant
Reduction from use of
LNG compared to
Oil-Based Fuels
CO2 Up to 50%
CO 70-90%
NOx 75-95%
Particular matter 90%
SOx 99%

LNG FEED GAS RATES
Typical LNG Product Specs
LNG FEED GAS & PRODUCT SPEC
MMSCFD
LNG
Production
(GPD)
TPD
0.9 10,000 16
2.2 25,000 40
4.5 50,000 81
8.8 100,000 162
11.1 125,000 202
13.3 150,000 242
17.8 200,000 323
22.1 250,000 404
44.4 500,000 808
88.8 1,000,000 1,616
Rates include nominal 10% addition inlet gas requirements
for fuel gas, utilities, and/or regeneration gas consumption
Component Value
Methane, Vol % 96%+
Ethane, Vol% <4%
Propane and Higher,
Vol%
<2%
Hexane and Higher,
Vol%
0%
Oxygen, Vol% 0%
Nitrogen, Vol% <4%
CO2, ppm(v) <50
H2S, ppm (v) <1.0
H2O, ppm(v) <0.1
Mercury, Vol% 0%
LNG FEED Gas Rates

Diesel Gallon Equivalent (DGE) for
LNG is approximately 25-30% less
than diesel at current market
prices
30-40% of the cost of LNG on the
market is attributed to the
liquefaction costs
By reducing liquefaction costs, the
more attractive and profitable
LNG becomes
Can be accomplished by lowering
capital & operating costs by
combining NGL plants with LNG
production
Cost savings for consumers
ECONOMIC BENEFITS

COUPLING LNG PRODUCT
WITH NGL PLANTS

Midstream market concentrates on
selling residue gas and NGL Product
LNG can become a common product in
Midstream to increase revenues
Shorter market distribution chain =
more distribution options
Economically beneficial due to the
facilities’ commonalities
 Capital Cost Savings: approximately
35-45% saved versus a standalone LNG
plant
 Operating Cost Savings: approximately
20-30% as opposed to two standalone
units
DISTRIBUTION & ECONOMICS

FACILITY UNIT COMPOSITIONS
Plant Unit
NGL Recovery
Plant
Common LNG Plant Notes
Inlet Gas Separation & Heavy
Hydrocarbon Removal
X X X
LNG plant utilizes the NGL plant to remove the
heavy hydrocarbons
Gas Treatment
(CO2 and H2S) Removal
X X X
LNG plant utilizes the NGL plant treatment
system to remove impurities
Water Removal X X X
LNG plant utilizes the NGL plant treatment
system to remove water
Control Room / Warehouse X X X
Flare X X X
Power Distribution System X X X
Liquefaction System X
LNG Storage X
LNG Truck Loading X
NGL Product Handling X X
Fuel Gas System X X X
Instrument Air System X X X
Plant Operations & Maintenance
Activities
X X X
Drain Systems X X X
Plant Siting & Permitting X X X

TECHNICAL CHALLENGES
& SOLUTIONS

Minimizing or combining impurity
removals and/or the pretreatment
system
 Pretreatment requirements:
LNG unit = cryogenic gas plant
• CO2 removal
• H2S removal
• Water removal
• Mercury removal
• Heavy Hydrocarbon removal
 Caveat:
LNG facilities require a higher purity
residue gas
• 50 ppm CO2 requirement
 Sharing of infrastructure costs
ADVANTAGES
Component Value
Methane, Vol % 96%+
Ethane, Vol% <4%
Propane and higher, Vol% <2%
Hexane and higher, Vol% 0%
Oxygen, Vol% 0%
Nitrogen, Vol% <4%
CO2, ppm(v) <50
H2S, ppm (v) <1.0
H2O, ppm(v) <0.1
Mercury, Vol% 0%

REMOVAL SPECIFICATION
Impurity
Cryo Removal
Specification
LNG
Pretreatment Removal
Specification
Reason for Removal
CO2 – Carbon Dioxide +/- 1.0-1.5 mole % Less than 50 ppm
Presence leads to solid formations in
cold box/demethanizer and potential
equipment damage
H2O - Water Less than 0.1 ppm Less than 0.1 ppm
Presence leads to hydrate formations
and potential equipment damage
H2S – Hydrogen Sulfide
& Mercaptans
Less than 4 ppm Less than 1.0 ppm
Presence leads to solid formations and
potential equipment damage
Mercury 100% Removal 100% Removal
Presence leads to degradation of
aluminum exchangers
Ethane
Typical Residue Gas Spec
of <1100 BTU/SCF
&
Liquid Spec of <2.0 C1/C2
Less than 4.0 mole %
During Ethane Rejection Mode, high
ethane content in LNG will break product
spec
Propane+ High Recovery Desirable Less than 2.0 mole %
During Ethane Rejection Mode, high
ethane content in LNG will break product
spec
Hexane + 100% Recovery Less than 0.02 mole %
Presence leads to solid formations and
potential equipment damage

Molecular Sieve
- Water removal
- CO2 removal
- H2S removal
Pros: Least amount of CAPEX and
OPEX
Cons: Regen waste gas handling
/ disposal issues
Amines
- CO2 removal
- H2S removal
Pros: Proven technology,
reduces/eliminates regen waste
gas
Cons: CAPEX, requires
downstream water removal, acid
gas vent disposal
Specialty Solvents
- Water removal
- CO2 removal
- H2S removal
Pros: Combined process
Cons: High CAPEX and OPEX, acid
gas vent disposal
PRETREATMENT DESIGN CONSIDERATIONS

LIQUEFACTION TECHNOLOGIES
NITROGEN REFRIGERATION
•Nitrogen refrigeration closed loop with compression and expansion in conjunction with a
Brazed Aluminum cold box
•Pros: Simplistic design and operating scheme
•Cons: Power intensive
•Ideal for LNG Production Rates of <250 K GPD
METHANE EXPANSION
•Utilizes a recycled methane gas in conjunction with compression, expansion, refrigeration,
and expansion
•Pros: Less power intensive than Nitrogen
•Cons: More complex design and operating scheme
•Ideal for LNG Production Rates of <250K GPD
MIXED REFRIGERATION
•Utilizes a mixed refrigeration closed loop process with compression and expansion
•Pros: Most efficient process
•Cons: Higher CAPEX and OPEX at lower production rates
•Best suited for LNG Production Rates of >200K GPD

Option 1
Treat the entire inlet gas stream
down to the desired CO2
specifications of <50 ppm
Option 2
Treat on the front end of the plant
for Cryo Requirements CO2
specifications. The add a back-
end treating technology to
remove CO2 to the desired inlet
LNG specification.
DESIGN ANALYSIS

Various cases were analyzed to
determine the breakpoint in
facility design between Option 1
and Option 2
Key design parameters in the CO2
removal processes to determine
the optimal design point.
 Amine Circulation Rate
 Amine Reboiler Duty
Used cases from 50 MMSCFD gas
plants to 200 MMSCFD gas plants
Determined the key parameters
for each case
For each selected flow rate both
options were reviewed
OPTIMIZATION ANALYSIS

Based on the following graphs, the
optimal point to treat the entire inlet gas
stream to LNG specifications for a plant is
under 100 MMSCFD inlet rate (Option 1)
Amine circulation rate is prohibitively
higher rate once the facility is larger than
100 MMSCFD
Reboiler duty has an inflection point at
about 100 MMSCFD inlet gas
Inlet gas rates over 100 MMSCFD lead to
back end treating of LNG.
Depending on composition, conditions,
etc. the size around 100 MMSCFD would
need a detailed study to best determine
the optimal configuration
OPTIMAL DESIGN

AMINE CIRCULATION RATE COMPARISON
0
100
200
300
400
500
600
50 75 100 150 200
AmineCirculationRate(gpm)
Inlet Gas Flow Rate (MMSCFD) @ 2 Mole% CO2
Front End Treating Only Front End with Back End Treating
Treat to 50 ppm
Treat to 1 mole %

AMINE REBOILER COMPARISON
0
5
10
15
20
25
30
35
50 75 100 150 200
AmineReboilerDuty(MMBtu/h)
Inlet Gas Flow Rate (MMSCFD) at 2mole% CO2
Front End Treating Only Front End and Back End Treating
Treat to 50 ppm CO2
Treat to 1 mole %

AMINE CIRCULATION RATE DIFFERENCE
0
50
100
150
200
250
300
50 75 100 150 200
CirculationRateDifference(gpm)
Inlet Gas Flow Rate (MMSCFD)
Circulation Difference

INLET FLOW RATE CASES
Inlet Gas
Flow
(MMSCFD)
Amine Circulation for
Inlet Gas Treating to
50 ppm CO2
Amine Circulation for
Inlet Gas Treating to
1 mole% CO2
Delta Amine
GPM
Percent
Increase
50 130 75 55 73%
75 195 105 90 86%
100 225 140 115 82%
150 390 205 185 90%
200 525 270 255 94%

Cost savings
 Capital costs
• 35-45% savings due to pairing of
infrastructure commonalities
 Reduce liquefaction costs
• 30-40% of the overall LNG price
LNG
 Diesel gas equivalent is 25-30% less than diesel
 More environmentally friendly
 Additional product provided to the market for
sales
Optimal Design
 Full Inlet Treating is best for gas plants
under 100 MMSCFD
 Partial Inlet Treating is best for gas plants
over 100 MSSCFGD
 Studies are best to be completed for gas plants
around 100 MMSCFD in size
ADVANTAGES AND OPTIMIZATION

Maximizing the Gas Processing Market by Combining NGL Recovery with LNG

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