AbstractThe combination of changing global markets for natu-

ral gas liquids (NGL) with the simultaneous increase inglobal demand for liquefied natural gas (LNG) has stim-ulated an interest in the integration of NGL recoverytechnology with LNG liquefaction technologies.Historically, the removal of “heavy” or high-freezing-point hydrocarbons from the feed to LNG plants has beencharacterized as “gas conditioning” and achieved usingone or more distillation columns. While some attempts toprovide reflux to the distillation columns marginallyenhanced NGL recovery, little emphasis was placed onmaximizing NGL recovery as a product from the LNGprocess. As such, the integration of the two processeswas not a priority. Integrating state-of-the art NGLrecovery technology within the CoP LNGSM Process1, for-merly the Phillips Optimized Cascade LNG Process,results in a significant reduction in the specific powerrequired to produce LNG, while maximizing NGL recov-ery. This corresponds to a production increase in bothLNG and NGL for comparable compression schemes ascompared to stand-alone LNG liquefaction and NGLextraction facilities. In addition, there are potentialenhancements to the overall facility availability and proj-ect economics using the integrated concept. This inte-grated concept has been applied to three ongoing inter-national NGL/LNG projects using the CoP LNG Process.In these cases, LNG production has increased by approx-imately 7%, while using the same process horsepower.

1.0 IntroductionDue to clean burning characteristics and the ability to

meet stringent environmental requirements, the demandfor natural gas has increased considerably over the pastfew years. Projections reflect a continued increase for thenext several years. However, it is a clean burningmethane rich gas that is in demand as opposed to the typ-ical raw gas that exists in nature, which often includesadditional components such as heavier hydrocarbonsand other impurities. The heavier hydrocarbons, onceseparated from natural gas, are referred to as LiquefiedPetroleum Gas (LPG) and Natural Gas Liquids (NGL).Impurities may include carbon dioxide, hydrogen sul-fide, mercaptans, nitrogen, helium, water, and even tracecontaminants such as mercury and trimethylarsine.

Natural gas must be “conditioned” prior to liquefactionto remove undesired components. This “conditioning”normally takes place in separate or stand-alone facilitiesand typically includes the extraction of heavier hydrocar-bons such as LPG and NGL. The “conditioned” gas isthen typically fed to pipelines for distribution.

However, transportation to distant markets throughgas pipelines is not always economically or technicallyfeasible. As such, natural gas liquefaction has become aviable and widely accepted alternative. The economics ofliquefying natural gas is feasible due mainly to the greatvolume reduction achieved upon liquefying, which cre-ates the ability to store and transport large volumes. Thedemand for Liquefied Natural Gas (LNG) in NorthAmerica has increased considerably as energy demandshave increased at the same time wellhead gas supply topipelines has decreased. LNG is a natural alternative tosupplement gas pipelines as the infrastructure to processand burn the gas is largely in place. In addition, LNG isa highly reliable source of gas. For instance,ConocoPhillips’ Kenai, Alaska facility, which utilizes theCoP LNG Process, has supplied LNG to Japan for overthirty-five years without missing a single cargo. Figure 1is an aerial view of the recently constructed Atlantic LNG

Authors: Wesley R. Qualls, ConocoPhillips Company, Director,Technology Licensing; Shawn Huang, ConocoPhillips Company,Process Engineer; Doug Elliot, IPSI LLC President, Chief OperatingOfficer; Jong Juh (Roger) Chen, Sr. Vice President; R. J. Lee(Formerly) IPSI LLC; Jame Yao, Vice President, LNG TechnologyIPSI LLC; Ying (Irene) Zhang,Process Engineer, IPSI LLC

Benefits of Integrating NGL Extraction and LNG Liquefaction Technology

Copyright © – 2005, ConocoPhillips Company

Published in the proceedings of the AIChE 2005 SpringNational Meeting, 5th Topical Conference on Natural GasUtilization (TI) Session 16c – Gas.

Point Fortin, Trinidad, comprised of three trains and a fourth under construction, allutilizing a modernized version of the CoP LNG Process.

Figure 1

THE ATLANTIC LNG FACILITY – ARTIST RENDITION,

COURTESY OF ATLANTIC LNG COMPANY OF

TRINIDAD & TOBAGO

� 10 MTPA from Trains 1,2&3

� Integrated NGL Extraction

� 5 MTPA from Train 4 (Under Construction)

1

facility located in Point Fortin, Trinidad, comprised ofthree trains and a fourth under construction, all utilizinga modernized version of the CoP LNG Process.

Pentanes and heavier hydrocarbons, including aro-matics having a high freezing point, must be substantial-ly removed to an extremely low level in order to preventfreezing and subsequent plugging of process equipmentin the course of liquefaction. In addition, heavy compo-nents must also be removed in order to meet BTUrequirements of the LNG product. The heavy hydrocar-bons separated from LNG, may then be utilized as petro-chemical sales or for gasoline blending. In fact, NGLand/or LPG liquids may command a greater value thanLNG. Many efforts have focused on recovery of theseheavy hydrocarbons. However, most of the effort hasbeen placed on removal of the heavy hydrocarbons in aseparate NGL plant, located upstream of the LNG lique-faction facility.

Alternatively, since all components having a highercondensing temperature than methane will be liquefiedin the liquefaction process, it becomes technically practi-cal to integrate NGL recovery within LNG liquefaction.Duplication of processing equipment and refrigerationrequirements are avoided with an integrated approach.In fact, a substantial cost savings may be achieved whenNGL recovery is effectively integrated within the lique-faction process.

There have been attempts for NGL recovery withinthe LNG facility.(1) For example, lighter NGL compo-nents are recovered in conjunction with the removal ofC5+ hydrocarbons using a scrub column in a propanepre-cooled mixed refrigerant process, as disclosed in theliterature.(2, 3) The NGL recovery column is oftenrequired to operate at a relatively high pressure (typical-ly above 550 psig) in order to conserve refrigeration com-pression horsepower requirements. Although refrigera-tion horsepower is conserved utilizing a high-pressurecolumn, separation efficiency is often significantlyreduced due to less favorable operating conditions, i.e.lower relative volatility.

With careful integration of the NGLrecovery and LNG processes, the overallefficiency of the integrated process can besignificantly improved, thereby increasingNGL recovery and reducing specific powerconsumption.(4) This paper providesexamples of NGL recovery technology inte-grated within the CoP LNG Process, whilealso presenting recovery and efficiency per-formance.

2.0 Traditional Stand-Alone GasPlant Upstream of LiquefactionPlant

A number of NGL recovery processeshave been developed for natural gas andother gas streams.(5, 6, 7) Among variousNGL recovery processes, the cryogenicexpansion process has become the pre-

ferred process for deep hydrocarbon liquid recoveryfrom natural gas streams. Figure 2 depicts a typical cryo-genic expansion process configuration. In the conven-tional turbo-expander process, feed gas at elevated pres-sure is pretreated for removal of acid gases, water,mercury and other contaminants to produce a purifiedgas suitable for cryogenic temperatures. The treated gasis typically partially condensed utilizing heat exchangewith other process streams and/or external propanerefrigeration, depending upon the gas composition. Theresulting condensed liquid, containing the less volatilecomponents, is then separated and fed to a medium orlow-pressure fractionation column for recovery of theheavy hydrocarbon components. The remaining non-condensed vapor, containing the more volatile compo-nents, is expanded to the lower pressure of the columnusing a turbo-expander, resulting in further cooling andadditional liquid condensation. With the expander dis-charge pressure essentially the same as the column pres-sure, the resulting two-phase stream is fed to the top sec-tion of the fractionation column. The cold liquid portionacts as reflux, enhancing recovery of heavier hydrocar-bon components. The vapor portion combines with thegas in the overhead of the column. The combined gasexits the column overhead as a residue gas. After recov-ery of available refrigeration, the residue gas is thenrecompressed to a higher pressure, suitable for pipelinedelivery or for LNG liquefaction.

The fractionation column (as described) acts essential-ly as a stripping column since expander discharge vaporsare not subject to rectification. As such, a significantquantity of heavy components remains in the gas stream.These components could be further recovered if subject-ed to rectification. In an attempt to achieve greater liquidrecoveries, recent efforts have focused on the addition ofa rectification section and methods to effectively generatean optimal rectification reflux stream, e.g. the gas sub-cooled reflux illustrated in Figure 2.

2

H2S/CO2Removal

(Optional)

NGL

(C2+ or C3+)

Reboiler

P r o p a n eRe f r i g e r a t i o n

E x p a n d e r /C o m p r e s s o r

Demethanizer

Dehydration

H2O NGL Extraction

Feed Gas

To Pipeline or LNG PlantRecompression

Figure 2

BLOCK DIAGRAM FOR TYPICAL NGL EXTRACTION PLANT

Figure 3 illustrates a typical block diagram of the LNGfacility. Gas comprising predominantly methane entersthe LNG facility at elevated pressures and is pretreated toproduce a feedstock suitable for liquefaction at cryogenictemperatures. Pretreatment typically includes theremoval of acid gases (hydrogen sulfide and carbon diox-ide), mercaptans, water, mercury, and other contami-nants. The treated gas is then subjected to a plurality ofcooling stages by indirect heat exchange with one ormore refrigerants, whereby the gas is progressivelyreduced in temperature until complete liquefaction. Thepressurized LNG is further expanded and sub-cooled inone or more stages to facilitate storage at slightly above

atmospheric pressure. Flashed vapors and boil off gasare recycled within the process.

Because LNG liquefaction requires a significantamount of refrigeration energy, the refrigeration sys-tem(s) represent a large portion of a LNG facility. Anumber of liquefaction processes have been developedwith the differences mainly residing on the type of refrig-eration cycles employed. The most commonly utilizedLNG technologies are:

1) CoP LNGSM Process(8) This process, formerlyknown as the Phillips Optimized Cascade LNG Process,utilizes essentially pure refrigerant components in anintegrated cascade arrangement. The process offers highefficiency and reliability. Brazed aluminum exchangersare largely used for heat transfer area, providing for arobust facility that is easy to operate and maintain.Refrigerants typically employed are propane, ethyleneand methane.

2) Propane pre-cooled mixedrefrigerant process (9, 10) Thismixed refrigerant process providesan efficient process utilizing a multi-component mixture of hydrocarbonstypically comprising propane,ethane, methane, and optionallyother light components in one cycle.A large spiral wound exchanger isutilized for the majority of heat trans-fer area. A separate propane refrig-eration cycle is utilized to pre-coolthe natural gas and mixed refrigerantstreams to approximately –35 °F.

3) Single mixed refrigerantprocess(11) This process includesheavier hydrocarbons in the multi-

component mixture, e.g. butanes and pentanes, and elim-inates the pre-cooled propane refrigeration cycle. Theprocess presents the simplicity of single compression,which is advantageous for small LNG plants.

Historically, the removal of heavy hydrocarbons fromnatural gas is considered part of feed conditioning. Inmost cases, the residue gas (comprising primarily ofmethane) from a NGL recovery plant is delivered to theLNG facility for liquefaction. It is common practice forNGL extraction to stand-alone as a separate plant fromLNG liquefaction facilities for various commercial or geo-graphical reasons. One such commercial reason is whenNGL recovery and sales are desired well in advance ofLNG. There may also be geographical reasons to takethis approach such as cases where NGL liquids arerequired in a different location than LNG and where along gas pipeline separates the two plants. As still anoth-er reason, the NGL recovery plant may already exist,prior to consideration of a LNG facility.

3.0 Process Description of an Integrated NGLand LNG plant

A block diagram for an integrated LNG and NGLprocess is presented in Figure 4. For the purposes of thispaper, the CoP LNG Process was used for the LNG liq-uefaction technology. Treated natural gas is first cooledby utilizing refrigeration from within the liquefactionprocess in one or more stages and then introduced into adistillation column, or Heavies Removal Column. Figure4 represents the simplest embodiment of NGL integra-tion, where the Heavies Removal Column is not refluxedother than with condensed liquids contained within thecolumn feed. Once the feed has entered the column, it isseparated or in this case stripped. A bottoms stream, pri-marily comprised of NGL components, and a methanerich overhead stream are formed. The methane rich over-head stream is chilled, condensed, and in most cases sub-cooled within the liquefaction process. Once liquefiedand subcooled, the stream is subsequently flashed to nearatmospheric pressure in one or more steps in preparationfor LNG storage. Flashed vapor is used as a methane

3

High

DehydrationH2S/CO2Removal

(Optional)

H2O

Feed GasHeavy

ComponentRemoval

LNGLiquefaction

LNG

Figure 3

BLOCK DIAGRAM FOR TYPICAL LNG PLANT

NGLLiquefaction

H2S/CO2Removal

LNG

Liquefaction

RefrigerantSystem

NGL

Recovery

NGL

(C2+ or C3+)

Dehydration

H2O

*

Feed Gas

LNGNatural Gas

Refrigerant

* Reflux stream for lean methane configuration.

Dee

tha

niz

er

Hea

vies

Rem

ova

lC

olu

mn

Figure 4

BLOCK DIAGRAM SHOWING THE INTEGRATED NGL AND LNG PROCESS

recycle refrigerant with a portion heated and compressedfor fuel. The liquid stream from the Heavies RemovalColumn is introduced to a second distillation column inone or more feed trays, depicted in Figure 4 as aDeethanizer. In the second column, the liquid stream isseparated into a bottoms stream and a vapor overheadstream, primarily comprised of ethane and lighter com-ponents. The second column acts primarily as a deetha-nizer or partial deethanizer or in some cases adepropanizer or partial depropanizer, depending on thedesired BTU level of the LNG product and desired levelof propane and/or ethane recovery. The second columnbottoms stream may be routed to further fractionation inorder to separate the NGL and/or LPG liquids into thedesired product slate.

NGL recovery integration not only reduces capitalinvestment through re-utilizing essentially all equipmentin the NGL facility for LNG production, but alsoimproves overall thermodynamic efficiency. There aresignificant advantages in the following aspects:

� The overall integrated process reduces combined cap-ital and operating costs.

� The integrated process reduces combined CO2 andNOX emissions by improving the thermodynamic effi-ciency of the overall process.

� Higher recovery of propane (and ethane) is achiev-able.

� Most NGL process equipment is already utilized inLNG liquefaction plants.

In the integrated process for cryogenically recoveringethane, propane, and heavier components, the HeaviesRemoval Column in the LNG facility replaces the NGLrecovery column in the NGL plant, thereby reducing cap-ital expenditure. Through adjusting operating conditions,the level of NGL recovery can be optimized in accordancewith required specifications and the relative marketprices of LNG, LPG and NGL. Only one common utilityis required in the integrated plant, resulting in additionalsavings in capital expenditure. If well planned, the NGLrecovery portion of the plant may be constructed at anearlier stage and later integrated into the LNG liquefac-tion plant. The opportunity for early NGL sales may sig-nificantly improve LNG project economics. The flexibledesign of an integrated plant allows for an easy transitionbetween ethane recovery or ethane rejection, which isuseful given relatively frequent changes in ethanedemand.

Since integration of NGL recovery into the natural gasliquefaction process allows for higher recovery of heavierhydrocarbon components, the removal of liquefactioncontaminants such as cyclohexane and benzene are alsoimproved. This is important since these particular com-ponents, even at relatively low concentrations, may cre-ate freezing problems in the colder sections of the LNGprocess. Thus higher NGL recovery and less operational

concerns are achieved at the same time that the front-endNGL plant is eliminated.

4.0 Variations of the Integrated PlantsGreater recovery of LPG and NGL products is possi-

ble by supplying a rectification section to the HeaviesRemoval Column and selecting an optimal method ofreflux. Various configurations exist, depending on thecomponent selected for recovery as well as the desiredrecovery level. Of course, multiple streams within theliquefaction section may be utilized for reflux to this col-umn. The cases that follow are not an exhaustive list butrather the more common choices as integrated within theCoP LNG Process.

Case 1 No-reflux caseThe simplest embodiment of integrated NGL recovery

utilizes a Heavies Removal Column with the only refluxessentially from liquids contained within the columnfeed.

Case 2 Lean Methane Reflux Scheme A lean methane stream is condensed within the lique-

faction process and introduced as reflux to the HeaviesRemoval Column. In the CoP LNG Process, there aremultiple sources that may be used for lean methanereflux, each containing extremely low concentrations ofheavy components. Lean methane used as refluxenhances NGL recovery efficiency within the column,subsequently reducing NGL components in the overheadstream to a minimum. Thus, a higher NGL recovery isachieved even at relatively high operating pressures, inthe range of 600 psig. Of course, lean methane reflux ismore advantageous for ethane recovery operations.

Case 3 Deethanizer overhead reflux scheme In this configuration, Heavies Removal Column reflux

is generated from the deethanizer overhead. Refer toFigure 4. The deethanizer overhead is partially con-densed with the liquids or a portion of the liquids intro-duced to the top of the deethanizer as normal reflux. Thevapor or a portion of the vapor is compressed, partiallycondensed and introduced to the Heavies RemovalColumn as reflux. This reflux stream is rich in ethane,which provides an excellent choice for propane recovery.It is possible to operate the deethanizer as a demethaniz-er, providing a methane rich reflux to the HeaviesRemoval Column. Thus, operation may be easilyswitched between propane and ethane recovery simplyby adjusting operating parameters.

5.0 Case Study AssumptionsThe cases described above; no-reflux, lean methane

reflux, and deethanizer overhead reflux were studiedwith the results presented in this paper. Each integrationconfiguration was modeled at varying levels of propanerecovery. For propane recovery specifications, a 2.0mole% maximum C2:C3 ratio was used, consistent with

4

commercial-quality propane. A case was modeled forethane recovery as well, assuming an 85% ethane recov-ery target. For ethane recovery specifications, a 2.0mole% maximum C1:C2 ratio was used, consistent withcommercial-quality ethane.

The LNG production rate for each case examinedassumes that gas turbine drivers are utilized to providerefrigeration requirements for the liquefaction process.The available power is based on 25oC (77oF) ambient airtemperature. For consistency, gas-treating requirementsare identical in all cases as well as the gas turbine horse-power. Table 1 summarizes the parameters for the casestudies.

The Net Present Value (NPV) calculation is based on a20-year production life assuming a 10% discount rate.Installation costs for storage tanks, compressors, turbines,and other common equipment were assumed to be thesame for all cases. The following premises are used forNPV comparisons.

� The no-reflux integration case requires the lowest cap-ital expenditures. As such, it provides a convenientbasis for comparison. Installation costs for the no-reflux integration or base case are assumed at $200MM for 0% propane recovery.

� Installation costs for small changes in feedrates are estimated using the six-tenthsrule.

� The stand-alone or non-integrated NGLrecovery case required $5 MM for addi-tional equipment and $5 MM for externalpropane refrigeration for a total of $10 MMover the base case.

� The lean methane reflux integration caserequired $4 MM for additional equipmentover the base case.

� The deethanizer overhead reflux caseincludes $5 MM for additional equipmentover the bases case.

6.0 Comparison of Non-Integrated FacilitiesWith Integrated Facilities

Propane Recovery CasesTable 2 compares the performance of the stand-alone

or non-integrated case and three different integratedcases, no-reflux, lean methane reflux, and deethanizeroverhead reflux. Incremental NPV calculations areincluded. For clarification of terms, the definition of spe-cific power consumption is the required compressorpower divided by feed gas flow rate (HP/MMSCFDFeed). As revealed in Table 2, the specific power con-sumption of the deethanizer overhead reflux case isabout 4% lower than that of the stand-alone non-inte-grated case. The comparison also reveals that from theaspect of specific power consumption, integrated config-urations utilizing no-reflux and lean methane reflux donot result in significant advantages. In fact, the resultsreveal that the integrated process with no-reflux requiresmore specific power than the non-integrated case. On

the other hand, the integrated case utilizing deetha-nizer overhead as reflux resulted in higher LNG andNGL production capacities as compared to the othercases.

The study revealed that liquid recovery cases forintegrated facilities utilizing no-reflux or leanmethane reflux were not as efficient for propanerecovery and did not allow for optimal heat integra-tion. The integrated process utilizing deethanizeroverhead as reflux overcame these limitations,allowing for higher efficiency and liquid recovery.In addition, since efficiency is improved and instal-lation costs remain lower, a higher NPV is realizedas compared to the non-integrated case, where NGLrecovery is achieved in a stand-alone facility. This

effectively demonstrates the economic advantage of inte-grating NGL recovery within LNG liquefaction. Thecases presented efficiently integrated NGL recovery into

5

Feed Gas Composition Heat Sink for Cooling

Component Mole Percent Cooling Medium Ambient Air Nitrogen 0.10 Temperature (oF) 77 Carbon Dioxide 0.01 Methane 85.99 Inlet Feed Gas Pressure

Ethane 7.50 Pressure (psig) 1100 Propane 3.50 i-Butane 1.00 Liquefaction Cycle

CoP LNG Process n-Butane 1.00 i-Pentane 0.30 n-Pentane 0.20 Hexane Plus 0.40 Total 100.00

Table 1

PROCESS PARAMETERS FOR CASE STUDIES

Propane Recovery Ethane Recovery

Case Description Integrated NGL and LNG Facilities Integrated Facilities

Base

Integration With No-Reflux

Lean Methane Reflux

Deethanizer Overhead

Reflux

Lean Methane Reflux

Standalone Deviation Deviation Deviation

Overall Performance

Feed Gas, MMSCFD 660 603 -8.7% 661 0.0% 690 4.5% 705

Ethane Recovery, % 85.8%

Propane Recovery, % 98.5% 95.0% -3.6% 95.0% -3.6% 95.0% -3.6% 100.0% Relative LNG Production @ 93% Availability, MTPA 100 93 -7.0% 102 2.4% 107 7.2% 90 Relative NGL Recovery, BPD 100 89 -11.2% 97 -2.6% 102 1.8% Relative Specific Power, HP/MMSCFD Feed 100 110 9.5% 100 0.0% 96 -4.3% 94

Incremental NPV (20 yrs, 10%), $MM -266 52 217

Table 2

PERFORMANCE OF NON-INTEGRATED AND INTEGRATED CASES

Economic Basis: LNG – $2.5/MMBTU; NGL - $17/BBL; Feed - $0.5/MMBTU

LNG liquefaction technology while allowing for higheroverall propane recovery as well as that of heavier com-ponents, in excess of 95% from the feed gas. The opti-mized integrated process allows for recovery of over 99%for propane and heavier hydrocarbon. Higher propaneand NGL recovery is achieved while requiring less ener-gy and also eliminating the stand-alone NGL plant, lead-ing to significant savings in operating as well as capitalcosts.

Ethane RecoveryAs revealed above, the integrated case using deetha-

nizer overhead as reflux for the Heavies RemovalColumn is effective for high propane recovery. Theoperating parameters may also be modified quite easilyfor enhanced ethane recovery. Table 2 illustrated theresults of the integration operation for ethane recoveryconditions using the same feed conditions listed in Table1. Ethane recovery above 85% was easily achievable forthis integration case. Again, multiple sources of leanmethane reflux may be utilized with comparable results.

The price of liquid ethane is historically cyclical,depending heavily on petrochemical feedstockdemands. When liquid ethane demand is high, increas-ing ethane recovery may generate additional revenue.On the other hand, it is often desirable to leave ethane inthe LNG product, while maintaining high propanerecovery when the ethane market is depressed. Due tothe cyclic nature of the liquid ethane, a facility providingflexibility to easily switch between propane and ethanerecovery allows producers to quickly respond to marketconditions.

Comparison of Reflux Schemes in IntegratedProcesses

The relative specific power consumption for the threeintegrated configurations are compared and presented inFigure 5. For the no-reflux case, relative specific powerfirst decreases but then increases as propane recoveryincreases. Once propane recovery is higher than about

75%, relative specific power becomes a strong function ofthe desired propane recovery level. Essentially, this isdue to the fact that the liquid recovery section of the no-reflux scheme is not very efficient, requiring additionalhorsepower to achieve high propane recovery.

By comparison, the relative specific power of thedeethanizer overhead reflux case continues to decrease aspropane recovery increases. Given the same conditions,the deethanizer overhead reflux case requires the lowestspecific power consumption with the no-reflux caserequiring the highest. The trend is more evident at high-er propane recoveries. At 95% propane recovery, the spe-cific power of the deethanizer overhead reflux case is 4%less than the lean methane reflux case and 12% less thanthe no-reflux case. Of course, as propane recoveryincreases, the NGL product rate also increases.Generating natural gas liquids (NGL) requires less refrig-eration than liquefying methane-rich natural gas (LNG).

Therefore, the deethanizer overhead reflux configurationrequires less specific power (HP/MMSCFD) at highpropane recoveries and also improves overall facilitythermal efficiency.

Figure 6 illustrates the dependence of incrementalNPV on propane recovery level for the three differentNGL recovery configurations. The basis for comparisonof incremental NPV is the no-reflux case at 0% propanerecovery. For the no-reflux base case, incremental NPVfirst increases but then decreases as propane recovery isincreased. As one would expect from the specific powerrequirements results revealed in Figure 5, the incremen-tal NPV of the deethanizer reflux case continues toincrease as propane recovery increases. While, NPV forthe lean methane reflux case is higher than the no-refluxcase, the deethanizer overhead reflux case is clearly a bet-ter choice for high propane recovery requirements.

Operating pressure of the Heavies Removal Columnis ultimately limited by the critical pressure of the hydro-carbon mixture in the column. As the column pressureapproaches the critical pressure, relative volatilitydecreases significantly, resulting in a decreased capacityfor fractionation. However, the deethanizer overheadreflux configuration is capable of providing an ethane-

86

88

90

92

94

96

98

100

102

104

106

108

110

0 10 20 30 40 50 60 70 80 90 100

Base Case, C5+ Removal

No-Reflux Scheme

Methane Reflux Scheme

Deethanizer Overhead Reflux Scheme

Stand-Alone

Rel

ati

veS

pec

ific

Po

wer

, HP

/M

MS

CFD

C3 Recovery, %

0

100

200

300

400

500

600

700

800

900

0.0 20.0 40.0 60.0 80.0 100.0

Basis: Feed - 0.5 $/MMBtu; NGL - 17.0 $/BBL; LNG - 2.5 $/MMBtuProject Period = 20 years in operation, Discount Rate=10%

Base Case, C5+ Removal

No-Reflux Scheme

Methane Reflux Scheme

Deethanizer Overhead

Reflux Scheme

C3 Recovery, %

Incr

em

en

tal N

PV

(20

Yr, 1

0%

),M

M$

Figure 5

COMPARISON OF RELATIVE SPECIFIC POWER REQUIREMENTS

AT VARYING PROPANE RECOVERY FOR DIFFERENT NGL

INTEGRATION CASES

Figure 6

INCREMENTAL NPV AT VARYING PROPANE RECOVERY

FOR DIFFERING INTEGRATED CASES

6

rich reflux stream to the top of the Heavies RemovalColumn, driving the column further away from the criti-cal pressure, thereby enhancing relative volatility.Therefore, overall separation efficiency is improved.Therefore, in order to achieve the same propane recoverylevels as the lean methane reflux case, much less reflux isrequired, further resulting capital and operating cost sav-ings. Table 3 provides a more detailed comparison of thedeethanizer overhead reflux and the lean methane refluxconfigurations.

The deethanizer overhead reflux case allows higher-pressure operation of the Heavies Removal Column as

compared to the lean methane reflux case. This is due tothe fact that the deethanizer overhead reflux configura-tion results in a higher critical pressure for the HeaviesRemoval Column. This allows for separation at highercolumn pressures, which accordingly allows for moreefficient use of refrigeration within the liquefaction(LNG) process. The end result is lower operating costs.Of course, the lower operating costs combined with lowerinstallation costs results in overall improved project eco-nomics. It is clear that proper integration of deethanizeroverhead reflux to the Heavies Removal Column pro-vides for efficient propane recovery within LNG liquefac-tion technology.

7.0 ConclusionsProper integration of NGL recovery technology with-

in LNG liquefaction technology results in significantadvantages by lowering overall capital cost requirementsand improving both LNG and NGL production. Throughcareful process selection and heat integration, the inte-grated LNG/NGL facility results in lower specific powerconsumption and increased NPV as compared to non-integrated facilities. As demonstrated in this paper, giventhe same horsepower, an approximate 7% LNG produc-tion gain is realized through careful integration.

Utilization of deethanizer overhead as reflux to theHeavies Removal Column improves separation efficiencywhile maintaining higher column pressures for efficient

and economical utilization of mechanical refrigeration.For high propane recovery, the deethanizer overheadreflux configuration requires less specific power andresults in improved project economics when compared toconfigurations using lean methane reflux or no reflux tothe Heavies Removal Column.

8.0 References1. Chiu, C.-H., LPG-Recovery Processes for

Baseload LNG Plants Examined. Oil & Gas Journal, 1997:p. 59-63.

2. Hudson, H.M., Wilkinson, J.D., Cuellar, K.T. andPierce, M.C. Integrated Liquids RecoveryTechnology Improves LNG ProductionEfficiency. 82nd Annual Convention of theGas Processors Association. 2003. SanAntonio, Texas.

3. Wilkinson, J., Hudson, H.,Cuellar, K. and Pitman, R., Efficiencythrough Integration. HydrocarbonEngineering, 2002, 7(12): p. 23-26.

4. Lee, R.-J., Yao, J., Chen, J.J. andElliot, D.G., Enhanced NGL RecoveryUtilizing Refrigeration and Reflux fromLNG Plants, U.S. Patent 6,401,486, (June 11,2002).

5. Lee, R.J., Yao, J., and Elliot, D.G.,Flexibility, Efficiency to Characterize GasProcessing Technologies. Oil & GasJournal, 1999, 97(50): p. 90-94.

6. Yao, J., Chen, J.J. and Elliot, D.G., Enhanced NGLRecovery Processes, U.S. Patent 5,992,175, (November 30,1997).

7. Yao, J., Chen, J.J., Lee, R.-J. and Elliot, D.G.,Propane Recovery Methods, U.S. Patent 6,116,050,(September 12, 2000).

8. Houser, C.G., Yao, J., Andress, D.L. and Low,W.R., Efficiency Improvement of Open-Cycle CascadedRefrigeration Process, U.S. Patent 5,669,234, (September23, 1997).

9. Rentler, R.J., Macungie, P. and Sproul, D.D.,Combined Cascade and Multicomponent RefrigerationMethod with Refrigerant Intercooling, U.S. Patent4,404,008, (September 13, 1983).

10. Newton, C.L., Process for Liquefying Methane,U.S. Patent 4,445,916, (May 1, 1984).

11. Swenson, L.K., Single Mixed Refrigerant ClosedLoop Process for Liquefying Natural Gas, U.S. Patent4,033,735, (July 5, 1977).

9.0 Endnotes1 CoP LNG services are provided by ConocoPhillips

Company, Phillips LNG Technology Services Companyand Bechtel Corporation through a collaborative relation-ship with ConocoPhillips Company. CoP LNG,ConocoPhillips and its logo are trademarks ofConocoPhillips Company. Bechtel and its logos aretrademarks of Bechtel Group Inc.

Case Description Lean Methane

Reflux Deethanizer

Overhead Reflux

C3 Recovery, % 95 95

Heavies Removal Column Reflux Relative Flow Rate, M3/Hr 226 100

C2 Content, mol% 4.6 56.3 Critical Pressure, Psia 769 978

Critical Temperature, oF -100 35

Heavies Removal Column Top Tray

C2 Content, mol% 5.4 10.1

Critical Pressure, Psia 793 865

Critical Temperature, F -94 -78 Relative Specific Power, HP/MMSCFD Feed 104.3 100

Table 3

COMPARISON OF LEAN METHANE REFLUX AND

DEETHANIZER OVERHEAD REFLUX

7

Author BiographiesDouglas G. Elliot, President, Chief Operating Officer

and co-founder of IPSI LLC, an affiliate of BechtelCorporation, in Houston, Texas, has helped developmuch of the technology currently used in the gas pro-cessing industry and is the author of more than 50 tech-nical publications, plus several patents. Doug has been amember of the Gas Processor’s Association ResearchSteering Committee since 1972. He holds a B.S. degreefrom Oregon State University and M.S. and Ph.D.degrees from the University of Houston, all in chemicalengineering. Doug is a Fellow of the American Instituteof Chemical Engineers, and a Bechtel Fellow, the highesthonor Bechtel offers for technical achievement.

Wes Qualls is currently a Director of LNG TechnologyLicensing in the ConocoPhillips’ Global Gas Group. Hehas over 16 years experience in refining, NGL processing,petrochemicals, chemicals & plastics, and upstream tech-nologies. His background includes process engineeringand design, commissioning & startup, and facility opera-tions. He currently manages licensing activities for bothtechnical and commercial efforts for multiple LNG proj-ects. He holds Bachelor of Science degrees in Chemicaland Mechanical Engineering from Texas A&MUniversity.

Shawn Huang joined ConocoPhillips in April 2001 asa Chief Engineer. He came to the U.S. in August 1987,after working as a research scientist at the Institute ofAtomic Energy. He joined Exxon in Houston in October1990 and Halliburton in February 2000 as a Principal. Hereceived his Ph.D. degree in Chemical Engineering fromthe University of Idaho in December 1990, and his MBAdegree from the University of Texas in May 2004.

R.J. Lee, Vice President of IPSI LLC, an affiliate ofBechtel Corporation, is a senior process engineer special-izing in oil and gas processing, cryogenic industrial gasseparation, and liquefied natural gas and enhanced NGLrecovery technology. He graduated from NationalTaiwan University in 1981 with a B.S. degree in ChemicalEngineering, and holds M.S. and Ph.D. degrees inChemical Engineering from Purdue University, Indiana.

Roger Chen is Senior Vice President of IPSI LLC, anaffiliate of Bechtel Corporation, and has more than twen-ty-eight years experience in research, process design anddevelopment in the areas of gas processing and oil andgas production. Roger holds a B.S. degree from NationalTaiwan University; M.S. and Ph.D. degrees from RiceUniversity, all in Chemical Engineering, and is a memberof AIChE, ACS and the Gas Processors AssociationResearch Steering Committee.

Jame Yao, Vice President of IPSI LLC, an affiliate ofBechtel Corporation, in Houston, Texas, has 23 yearsexperience in the development of gas processing andLNG technologies and is the author of more than 15 tech-nical publications, and more than 15 patents. Jame holdsa B.S. degree from National Taiwan University and M.S.and Ph.D. degrees from Purdue University, all inChemical Engineering. He is a member of the AmericanInstitute of Chemical Engineers.

Irene Zhang is a process engineer with IPSI LLC, anaffiliate of Bechtel Corporation. She joined IPSI LLC inMay 2002. Irene holds B.S. and M.S. degrees fromTsinghua University; and a Ph.D. degree from RiceUniversity, all in Chemical Engineering.

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