LPG Recovery Process

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Gastech 2005

COMPARE THE DIFFERENT OPTIONS FOR NGL RECOVERY FROM NATURALGAS

Henri ParadowskiAndre Le-Gall & Benoit Laflotte

Gas Processing DepartmentTechnip,

92973 Paris La Dfense, CEDEXFrance

ABSTRACT

As a result of the growth of the natural gas market, worldwide NGL production capacity has increased strongly andcontinuously in the last decades and this tendency is expected to continue for some years. NGL recovery activity seemsto be driven by its own market forces with a growth rate surpassing that of natural gas.

EPC contractors such as Technip have an important role to play in finding cost effective solutions for the NGL business.Technip has a policy of studying solutions to identify those that best meet the requirements of reliability, efficiency andcapital cost. Big improvements have been achieved by moving away from so-called standard practice and throughprocess development studies.

There are many options for the different steps of NGL production; in this paper we will compare alternative routes forselected steps:

Drying of natural gas,

Recovery of NGL from natural gas,

Fractionation of NGL into commercial products,

Refrigerated Propane Storage.Studies are presented which illustrate the methods used to identify and present reliable and innovative solutions. Theseexamples are based on natural gas similar to the Qatar North Field for dehydration and NGL recovery and on an NGLmixture similar to that fractionated in Venezuela for fractionation and refrigerated propane storage.

The studies use open art and Technip proprietary technologies.

The underlying experience comes from many LSTK projects in which Technip has been the EPC contractor.


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Gastech 2005 Paradowski 2

COMPARE THE DIFFERENT OPTIONS FOR NGL RECOVERY FROM NATURAL GAS

INTRODUCTION

As a major EPC Contractor, Technip has been involved in the conception, design, construction and initial operation ofmany large size gas treatment and NGL recovery plants over the last forty years.

In several instances follow-up contracts were executed for the same Client, either as debottlenecking projects

1

ornew capacity additions, therefore providing first-hand access to operating experience. The lessons learnt from pastprojects give the Contractor a powerful tool for the development of improved solutions that are of benefit to its Clients.

This paper focuses on specific aspects of NGL recovery units where the Contractor can bring a significant input.

BRIEF ANALYSIS OF THE NGL MARKET

The present paper is focused on NGL recovery from natural gas. In the analysis of the market drivers, a distinctionshould be made between ethane and LPG (propane, butanes and mixed LPG).

Ethane value is exclusively related to its potential use as cracker feedstock, and therefore its extraction is only

considered in the general framework of a downstream petrochemical development. In other cases, ethane has only fuelvalue.

The world LPG market has seen a significant market growth in the last decades, with an average growth of 2.9% peryear over the past ten years and a current worldwide production of over 210 million tonnes. This average growth isslightly higher than the corresponding growth in natural gas production, and nearly twice the average crude oilproduction growth.

The main drivers for LPG growth worldwide are the residential/commercial sector and uses as petrochemicalfeedstock, with significant regional disparities.

About 60% of world LPG production originates from natural gas, and this is the dominant source in North America,

Northern Europe, Africa and the Middle East.

To illustrate the market driven nature of NGL production, Figure 12compares the average North American spot pricesfor natural gas (Henry Hub), propane and n-butane (Mount Belvieu). All product prices are referred to their calorificvalue.

1Increasing NGL Plant capacity, H. Paradowski, L. Barthe and D. Gadelle, GPA European Chapter, Heidelberg Sept. 2003

2Adapted from EIA / Barnes and Click


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Sources: EIA / Barnes and Click

Henry Hub / Mount Belvieu monthly spot averages

Natural Gas, Propane, n-Butane

Natural gas

Propane Butane

Natural gas

Figure 1: Natural Gas, Propane and Butane prices (in US$/MMBTU)

Although this approach could be accused of oversimplification, the comparison suggests that there is a marketincentive to extract the LPG, except for limited periods of time (winter 2000, winter 2003). More detailed studies indicatethat the extraction of LPG in North America3and in Northern Europe4show positive margins. This situation translates intosignificant margins in areas of cheap natural gas from which LPG can be sold at market price.

To sustain this current and projected market growth, several larger size gas treatment / NGL production projectshave been scheduled or implemented such as the NGL-4 and Dolphin Projects in Qatar, Berri debottlenecking in Saudi

Arabia, OGD-3/AGD-2/Ruwais-3 projects in UAE, the Western Libya Gas Project and the Ohanet project in Algeria amongothers.

Additional NGL will be produced in a number of LNG plants that are under implementation or at various project

stages.

3Uncertainty about gas quality could delay US LNG imports, D.J. Hawkins , OGJ Sept. 20, 2004

4North Sea Gas Processing Margins, Purvin & Getz, GPA European Chapter, London Nov. 2004


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GAS AND NGL CHAINS : FROM WELLHEAD TO THE CONSUMER

From wellhead to consumer, each of the products to be valorised has to be extracted, purified and transported.

The typical line-up of a sales gas and NGL production chain includes:

Collection and transport from wellhead to processing plant,

Condensate separation and stabilisation for storage and export,

Gas sweetening (H2S, CO2, other sulphur compounds if appropriate) with associated sulphur recovery, if required,

Gas dehydration,

LPG extraction, ethane extraction when desirable,

LPG (and/or ethane) purification to the required specification, storage and export,

Sales gas export to distribution network.

Depending on the nature of the raw natural gas, and in particular, on the amount of contaminants present from thereservoir, an optimised line-up has to be developed.

A simple gas plant, based on lean natural gas and producing LPG might be limited to a few processing steps (glycoldehydration, LPG recovery). More complex feedstock will require additional processing steps and leave room for morecomplex engineering developments. Typically, optimisation issues are focused around:

Selection of the acid gas removal process (type of solvent, H2S vs. CO2selectivity, requirement to removeother sulphur compounds...),

Selection of the dehydration technology,

Optimisation of the NGL recovery unit to best match the required level of product recovery, flexibility (ethanerecovery vs. ethane rejection) and operability constraints,

Selection of NGL product purification schemes, including handling of by-products such as disulphide oil in thecase of caustic washing of LPG in the liquid phase to remove mercaptans, or regeneration gas handlingshould gas phase removal of mercaptans be selected.

Such situations are commonly encountered in the Middle East and in the Caspian area, where raw gases aregenerally wet and sour. Similar situations exist, to a lesser extent in, Africa and South East Asia. All of them posesignificant challenges to the process designer making each gas treatment and NGL recovery plant unique.

A second factor that makes each gas plant unique is the relative location of the gas field vis--vis the export facilitiesand the targeted market of each of the products. There are few similarities between the issues to be resolved for astraddle plant, located close to a petrochemical complex and a gas treatment plant in a remote producing area, asencountered for instance in Saudi Arabia and in Abu Dhabi.


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A GAS PROJECT EXAMPLE : WLGP

The gas field geographical location offers additional challenges to the project developers and the engineeringcompanies. The Western Libya Gas Project offers a significant example of these complex issues5.

Figure 2: Western Libya Gas Project schematic

The Western Libya Gas Project valorises gas and oil from the Wafa Desert field (located 500 km inland) and gas from

the Bahr Essalam field located 100 km offshore. The final products are sales gas, stabilized crude oil, stabilizedcondensate, butanes and propane. The majority of the gas is exported to Italy by pipeline.

Three gas-processing plants have been built to achieve the project objectives:

1. The Wafa Desert Plant pretreats the oil and gas feedstock to allow pipeline transportation to shore where thefinal extraction and treatment is performed. The options selected for the Wafa Desert Plant are oil and gascondensate stabilisation, CO2 removal, gas dehydration and LPG extraction using a cryogenic process. Allliquids are commingled and transported to shore through a 16 pipeline. The sweet gas that has beenconditioned for transport (water and hydrocarbon dew-point) is compressed and sent to the coast through a32 pipeline.

2. The Mellitah Plant receives gas and condensate separately from the offshore field. Gas is treated to removeH2S and CO2 and is then dehydrated. Part of the LPG is removed and treated. Condensates from thecondensate pipeline and the gas pipeline slug catchers are stabilized.

3. Gas from Wafa Desert is mixed at the Wafa Coastal Plant with the gas from the Mellitah Plant and iscompressed for export. The liquids from Wafa Desert are fractionated at the Wafa Coastal Plant to yieldstabilised crude oil, butane and propane that are shipped separately.

5ENI web site, Investor Relations, October 2004


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PROCESSING OPTIONS FOR SELECTED STEPS IN NGL RECOVERY

In the remainder of this paper, we will illustrate examples of process options that may be considered whendeveloping a gas processing plant line-up. We will compare alternative routes, supported with calculations, for thefollowing steps:

Drying of natural gas,

Recovery of NGL from natural gas,

The studies that are presented for these two steps are based on natural gas from the Qatar North Field.

Fractionation of NGL into commercial products,

Refrigeration of Propane Storage.

These two examples are based on an NGL mixture from Eastern Venezuela.

The studies use open art and Technip proprietary technologies. The underlying experience comes from many LSTKprojects in which Technip has been the EPC contractor.

The following tables provide in one block the basis of the different studies.

Basis for studies on Dehydration and NGL recovery

Nitrogen 4.0% mole

Methane 86.8% mole

Ethane 5.5% mole

Propane 2.1% mole

i-Butane 0.3% mole

n-Butane 0.5% mole

i-Pentane 0.2% mole

n-Pentane 0.2% mole

n-Hexane 0.2% mole

C7+ 0.2% mole

Table 1.1. Natural gas composition.


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NG temperature at dehydration inlet 34C

NG Pressure at dehydration inlet 62 bar abs

NG Pressure at NGL recovery inlet 60 bar abs

Sales Gas Pressure 60 bar abs

Fuel Gas Pressure 25 bar abs

Design Natural gas flow rate40,000 kgmole/h

(800 MMSCFD)

Process fluid outlet temperature: air cooledexchangers

34C

Centrifugal compressor efficiencies 82 %

Air temperature 28C

Available power for different gas turbinesGE 5 C 24,200 kWGE 5 D 27,900 kW

Table 1.2. Other fixed conditions.

Basis for Studies on NGL Fractionation

CO2 8.0% mole

Methane 0.1% mole

Ethane 28.9% mole

Propane 33.9% mole

i-Butane 7.6% mole

n-Butane 11.3% molei-Pentane 3.7% mole

n-Pentane 2.9% mole

n-Hexane 2.0% mole

C7+ 1.6% mole

Table 2.1. NGL Fractionation feed.

NGL Feed temperature 33C

NGL Feed pressure 24 bar abs

NGL Feed flow 245 t/hHot Water Furnace efficiency 90 %

Hot Oil Furnace efficiency 65 %

Steam Boilers efficiency 90 %

Steam Turbine adiabatic efficiency 80 %

Electric power generator efficiency 97 %

HP Steam pressure 63 bar abs

HP Steam temperature 440C

LP Steam pressure 5 bar abs



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Basis for studies on Refrigerated Propane Storage

Ethane 1.0% mole

Propane 98.0% mole

i-Butane 0.7% mole

n-Butane 0.3% mole

Table 3.1. Propane rundown composition.

Propane run down flow rate 160 t/h

Propane storage pressure 1.04 bar abs

Propane storage capacity 75,000 m3

Propane kettles approach (Wieland tubes) 2C


DEHYDRATION OF NATURAL GAS

Problem definition

When natural gas is processed in an NGL recovery unit the water content has to be decreased whether to avoid theformation of hydrates or to decrease the amount of hydrates formed and the size of the hydrates particles so that thehydrates will not accumulate and plug the equipment. It is known that hydrates formed at very low temperatures in smallquantities will not stick to the walls of heat exchangers, valves and other equipment and that they do not plugequipment. It is also known that hydrates can accumulate in dead end zones, where the velocity is reduced. Somedevices such as strainers or mesh pads can stop the hydrates crystals and allow a plug to build up.

Water content ppmmole

Natural gasat 62 bars

Natural gasat 30 bars

20 -20 -26

10 -27 -32

5 -33 -39

2 -42 -47

1 -49 -53

0.5 -55 -59

0.2 -64 -66

0.1 -70 -72Table 4. Hydrate formation temp. vs water content for natural gas at 62 and 30 bars.

Given that 0.1 ppm is a typical molecular sieve outlet gas specification for water content it can be observed fromTable 4 that in deep NGL recovery processes where the temperature reaches 100C it is not possible to avoid theformation of hydrates. However, the quantity that is formed when the water content is 0.1 ppm is extremely smalli.e. 0.07 kg/h, or 600 kg/year.

Molecular sieves: a standard option for deep NGL recovery

Based on the above consideration and our experience, the use of mol sieves that can achieve a water content of 0.1ppm in the dry gas seems a reasonable choice. It is also reasonable to operate the dryers on a fixed cycle basis to avoid

any breakthrough of water in the dry gas.


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The mol sieve drying unit is capital intensive mainly because of the cost of the vessels, remote operated valves,instruments, etc and not so much because of the cost of the zeolite. Any cost optimisation shall be done by thecontractor with support from a reliable mol sieve vendor.

Mol sieve dehydration units may be troublesome in operation; many problems that have been reported relate to theprocess design. A short list includes:

Carry over of liquids, water, hydrocarbons, causing caking of the adsorbent on the upper part of the bed andnear the walls of the vessel;

Presence of volatile basic compounds in the gas to be dried, these compounds can be production chemicalsor can come from the acid gas removal unit located upstream;

Presence of cations in the gas; the zeolites can be destroyed by an ion exchange process.

Refluxing phenomena occurring during regeneration of the adsorbent: the water formed on the walls willflow on the walls of the vessel and will damage the mole sieves by creating a cake;

The MS binder can be damaged during regeneration; the resulting phenomena would be the creation ofdust, increased pressure drop and crushing of the pellets;

This list is not exhaustive, but gives a feel of the many potential problems in operation. To minimize them the design

has be done with care. We, as a contractor, would concentrate our efforts on the following:

Design of the unit and its auxiliary systems by the contractor. It should not be considered as a black box:avoid packaged units, or strictly control the sub-contractor.

Use efficient upstream separation of liquids, but avoid creating mists which are very often the result of highshear stress;

Use simple regeneration sequences with a ramping up of regeneration gas temperature; this will help toavoid or reduce the refluxing phenomena; this shall be specified to the vendor;

Select the mol sieves and not the mol sieve vendor carefully: type, size of pellets, binder; it is important to

have a precise specification.

Install a robust filtration system downstream of the dryers.

TEG dehydration

Process design

Natural gas dehydration with TEG is a very simple process. Lean TEG is contacted with gas in a column usingstructured packing. The TEG water content is in the range of 0.1 to 0.2 % wt of water. This means that theregeneration of the rich TEG has to be performed using dry gas stripping at least.

This process has lower CAPEX and OPEX when compared to molecular sieves.

There are also fewer maintenance and operational issues, so that a TEG unit can easily be installed on anoffshore platform.

There are some design issues and the contractor shall be familiar with TEG technology to avoid mistakes withpotentially disastrous consequences, especially offshore where it is very difficult to add or modify equipment.

The most important design features from a process standpoint are:

Control of gas temperature at the inlet of the absorber,

Design of the absorber internals: distributors, structured packing, demisters, etc

Design of outlet separators to minimize losses of TEG by carry over; one has to remember that the meltingpoint of pure TEG is 5C so that it is very easy to freeze TEG in a cold separation unit.


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Parametric study

Using the data in Tables 1.1 and 1.2, the influence of the following parameters has been studied with a view todefining optimisation guidelines for large NGL recovery trains. The influence of the following parameters on the watercontent of dry gas has been covered by discrete studies:

Lean TEG water content,

Natural gas temperature,

Number of stages in the TEG absorber,

Natural gasTemperature

C

Number of stages TEG watercontent

% weight

Dry gas watercontent

ppm mole

34 3 0.1 11.2

34 4 0.1 6.3

24 3 0.1 4.0

24 4 0.1 2.9

24 3 0.2 6.5

24 4 0.2 5.5

Table 5. Effect of TEG Process Design Parameters on Dry Gas Water Content

The TEG absorption drying process is sensitive to three parameters

Lean TEG water content, which is related to the efficiency of gas stripping;

The temperature of the gas at the inlet of the absorber: precooling is very efficient way to obtain low watercontent in the dry gas.

The number of stages and hence the efficiency of the packing selected: this efficiency depends on packingtype, bed height and the quality of liquid and gas distributors;

These parameters are the result of choices made by the contractor with the support of reliable vendors of thecolumn internals.

NGL RECOVERY FROM NATURAL GAS

Problem definition

The study of the market for NGL has shown that there is no doubt about the profitability of propane, butane, andC5+ recovery from natural gas. The quantities available have to be such that the cost of infrastructure is not tooimportant.

For ethane recovery the situation is complicated because of the absence of a worldwide market for ethane. Manyoperators have come to the conclusion that ethane recovery does not pay or at best it is seen as a future possibility. Incountries where the government has future objectives for an ethane based petrochemical industry, many ERUs havebeen built for ethane recovery and rejection, but most of them have been operated in ethane rejection.

The process licensors of NGL recovery processes may advertise that the cost of the unit is not much affected by thischoice, the reality of a project including infrastructure is different: ethane recovery has a very significant impact onCAPEX and OPEX.

When the recovery of ethane is seen as a future possibility, it is possible to build a propane recovery unit withprovisions made for future conversion to ethane recovery.

The way this can be implemented is not so much a function of the process selected: all the processes use similar ifnot identical features and differ by details. It is the Contractors duty to allocate space in the lay out, accessibility, utilityconnections, etc


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Constant Ethane Production with variable Feed Gas

Each case is specific so that it is quite impossible to give thesolution. A problem that is met in Europe is that gasusage and production are variable. In winter the demand for gas is high, while in summer it is low. Underground gasstorage is not able to avoid seasonal variations completely.

This situation had to be considered for the ethane recovery unit designed in 1985 and built in 1987 in Lacq, France.As the ethane was feeding an ethylene plant, its production was required to be as constant as possible, whereas gasproduction was expected to fluctuate between winter and summer despite the use of the Lusagnet underground gasstorage facility.

Case study

We studied a similar but hypothetical case where the gas design capacity of the ERU is 800 MMSCFD (see Tables 1.1and 1.2) i.e. 40,000 kgmoles/h. The targeted ethane production is 400 kt/yr or slightly less than 50 t/h.

With an ethane content in the feed gas of 5.5% mole, the required ethane recovery rate is 72.4% and theproduction of pure C2 is 47.9 t/h in 50t/h of C2+ NGL. With this moderate extraction rate the Single Reflux Ethanerecovery process shown in Figure 3 is the more efficient choice. The Demethanizer column C1 is operated at 25 bars abs.

The sales gas compressor requires 23,600 kW of brake horsepower and could be driven by a GE5C or GE5D gasturbine or a VFD electric motor.

Now we consider what happens when seasonal variations in gas demand cause variations in feedstock of 600, 700and 800 MMSCFD for summer, spring and winter respectively. The ethane recovery rate must now be variable and highin summer. To meet these objectives the Dual Reflux Ethane recovery process is chosen.

The power available from the sales gas compressor drivers is used to maintain ethane production constant duringperiods of reduced natural gas throughput.

The following figures show the main characteristics of the resultant ERU at 800, 700, and 600 MMSCFD.

NGL (C2+)

Feed gas

T1 K1

E1

Sales gas

V1

E2

K2

C1

60 bar

25 bars

-94C

60 bar

34C

Ethane recovery 72.4% : 47,900 kg/h

Power 180 kW.h / t NGL

800 MMSCFD

-34C

7,600 kW738 MMSCFD

738 MMSCFD

23,600 kW

129,700 kg/h

GT

Figure 3: Single Reflux Ethane recovery process scheme (winter)


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NGL (C2+)

Feed gas

T1 K1

E1

Sales gas

V1

E2

K2

C1

60 bar

Ethane recovery : 84.8% 49,100 kg/h

Power 195 kW.h / t NGL84 MMSCFD

recycle7,100 kW

-34C

121,200 kg/h

641 MMSCFD725 MMSCFD

23,600 kW

25 bars

-99C

700 MMSCFD

GT60 bar

Figure 4: Dual Reflux Ethane recovery process scheme (spring)

NGL (C2+)

Feed gas

T1 K1

E1

Sales gas

V1

E2

K2

C1

60 bar

25 bars

-102C

GT

Ethane recovery : 96 % 47650 kg/hPower 215 kW.h / t NGL

-34C

109,500 kg/h

546 MMSCFD

60 bar

168 MMSCFD

recycle

714 MMSCFD

23,600 kW

600 MMSCFD

6,800 kW

Figure 5: Dual Reflux Ethane recovery process scheme (summer)

Operating case Winter Spring Summer

Feed gas flow rate MMSCFD 800 700 600

Recycle gas flow rate MMSCFD 0 84 168

Flow rate in sales gas compressor MMSCFD 738 725 714

Power of sales gas compressor kW 23,600 23,600 23,600

Ethane recovery rate % 72.4 84.8 96

Pure ethane recovered kg/h 47,900 49,100 47,650

NGL produced kg/h 129,700 121,200 109,500

Specific power consumption kW.h /t NGL 215 195 215

Table 6. Seasonal Operating Modes to maintain Constant Ethane Production


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This line up was used in the design of the Lacq plant. In the Lacq plant, two compressors operating in parallel,perform the compression of sales gas: a VFD motor driven compressor and a fixed speed asynchronous electric motordriven compressor. The gas that is recycled cannot be contaminated by seal oil as the compressors use dry seals. Thecontractor, Technip, fit the process to the specific Client (ELF in 1987, TOTAL nowadays after the merger of TOTAL FINAELF) constraints to maintain a constant ethane production.

Process optimisation

As understanding of the thermodynamics of NGL recovery have improved, new processes have been developed.

Technip was granted a patent in 2003 for a Multiple Reflux Ethane recovery process. This process, through the additionof a vessel V2 makes it possible to increase the ethane recovery rate at constant power consumption.

NGL (C2+)

Feed gas

T1 K1

E1

Sales gas

V1V2

E2

K2

C1

60 bar

Ethane recovery 88.6 % 51300 kg/h

Power 191 kW.h / t NGL7,100 kW

-34C

640 MMSCFD

123,400 kg/h

25 bars

-100C

GT60 bar

700 MMSCFD

84 MMSCFD

recycle

724 MMSCFD

23,600 kW

Figure 6: Multiple Reflux Ethane recovery process scheme

The MRE process is compared to the DRE process of the late 1980s in Table 7.

Operating case DRE MRE

Feed gas flow rate MMSCFD 700 700

Recycle gas flow rate MMSCFD 84 84

Flow rate in sales gas compressor MMSCFD 725 724

Power of sales gas compressor kW 23,600 23,600

Ethane recovery rate % 84.8 88.6

Pure ethane recovered kg/h 49,100 51,300

NGL produced kg/h 121,200 123,400

Specific power consumption kW.h /t NGL 195 191

Table 7. MRE vs. DRE Process Performance

Variable Ethane Production with constant Feed Gas

Ethane based ethylene plants when built in gas producing regions are frequently fed from multiple suppliers with nobuffer storage. This creates a requirement for variable ethane production, to be adapted to make full use of ethyleneplant capacity.

The following study therefore considers how to vary ethane recovery while keeping the propane recovery rate at99% or at least at more than 95%. To simplify the discussion we shall consider that the feed gas flow rate is constant.

Four main options were identified for study that differ in terms of CAPEX, OPEX and operability:

Option 1: Recover C2+ at a constant rate from the feed gas; fractionate C2+ into C2 and C3+, re-injectexcess C2 into the sales gas upstream of compression,


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Option 2: Adjust C2 recovery in a process designed for high C2 recovery by reducing the reflux andincreasing the temperature of the cold separator,

Option 3: Switch from a high C2+ recovery scheme to a C3+ recovery scheme in a bi-modal unit,

Option 4: Change operating conditions in a scheme built for the purpose of variable ethane recovery andhigh propane recovery.

Option 1: Reinject C2 into sales gas upstream of the compressionThis scheme is very robust and easy to operate. It requires distillation of the C2+ cut which increases CAPEX

compared to an ERU designed only for high ethane recovery. OPEX is also high with the paradox that energyconsumption is higher in ethane rejection than in ethane recovery. Today this option would be considered only ifdistillation of C2+ into C2 and C3+ is integrated in the gas plant and if the amount of excess ethane is low compared toethane production.

Option 2: Adjust C2 recovery

This scheme is very simple and easy to operate. It requires only an additional reboiler on the demethanizer. TheCAPEX is only slightly higher than an ERU designed only for high ethane recovery. The OPEX is also high: the paradox isthat the energy consumption is higher in ethane rejection than in ethane recovery. There is a decrease of propane

production. Today this option is considered only if the variation of ethane production is limited.

Option 3: Switch from C2 recovery scheme to C3 recovery scheme

This option is very simple in principle but requires skilled operators and good production scheduling. Compared to aC2 recovery scheme, it requires additional equipment and valves. CAPEX is higher than an ERU designed only for highethane recovery. This option has better OPEX than options 1 and 2 and better CAPEX than option 1. There is no decreaseof propane production. Today this option is considered on many projects.

Option 4: Slowly adjust parameters to gradually switch from C2 recovery scheme to C3 recoveryscheme

This option is also very simple in principle and robust. Skilled operators and good production scheduling are lesscritical. Compared to a C2 recovery scheme, it requires additional equipment and valves. The CAPEX is higher than option3 but it has better OPEX . There is no decrease of propane production. Today this option could be used on projectsrequiring high flexibility.


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NGL FRACTIONATION : AN ENERGY SINK

Observation

The NGL extracted from the natural gas has to be fractionated to produce the following commercial products:

Ethane, feedstock for ethylene production,

Propane, stored at atmospheric pressure and sold on the international market,

Iso-butane, stored at atmospheric pressure and sold on the international market, mainly in the USA

N-butane, stored at atmospheric pressure and sold on the international market as butane.

Stabilised C5+ cut, stored at atmospheric pressure and sold on the international market.

NGL fractionation uses simple principles but consumes large amounts of energy for the reboiling of the fractionationcolumns, about 300 kW.h / t of NGL or around 3% on an auto consumption basis.

Taking for example the fractionation unit built in Eastern Venezuela by the Technip group in the 90s and with referenceto Tables 2.1 and 2.2 the details are the following:

Duty of the reboilerkW

Product flow ratet/h

Product

Deethanizer 21700 65 Ethane

Depropanizer 17800 80 Propane

Debutanizer 11500 45 C5+

C4 Splitter 20000 55 Iso + n Butane

Total 71000 245

Table 8. NGL Fractionation Unit Energy Consumption

Solutions to minimize the energy consumption

To minimize primary energy consumption there are several known techniques:

Use process heat integration,

Combine fractionation of NGL with cogeneration.

These techniques can be future improved with the recovery of waste heat from an external source such as gasturbine exhaust gases if available close to the fractionation unit.

The first two approaches are compared with reboiling using pressurized hot water produced in a direct-fired heater.

NGL fractionation with heat integration

The following scheme shows the line up of the unit with heat integration used at one location. The main part of thebutane splitter reboiler duty is performed using heat rejected by the debutaniser condenser with trim heating using hotoil.


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Hot oil Hot oil

Ethane

65 t/h

NGL Feed

245 t/h

Deethaniser

Hot oil

C3

Depropaniser Debutaniser

C5+ 45 t/h

Hot oil

n-Butane

35 t/h

C4 splitter

Propane

80 t/h

i-Butane

20 t/h

integration

Figure 7: NGL fractionation with heat integration

However, to increase the debutaniser condensing temperature to a useable level the debutaniser pressure andbottom temperature has to be increased with the consequence that hot oil must be used as heating medium instead ofhot water. The hot oil temperature has to be relatively high so that the efficiency of the direct-fired heater used to heatthe hot oil falls to about 65% cancelling out much of the theoretical advantage.

NGL fractionation energy minimization with cogeneration

Another alternative is plant integration of the process units with utility generation. If the process heat integration ofFigure 7 is abandoned, the scheme becomes that of Figure 8. The temperature of the bottom of the debutaniser columnis low, similar to the other columns, so that it is possible to use low-pressure steam from the LP discharge of a steamturbine (Figure 9) used for power generation.

LP Steam LP Steam

Ethane

65 t/h

NGL Feed

245 t/h

Deethaniser

LP Steam

C3

Depropaniser Debutaniser

C5+ 45 t/h

LP Steam

n-Butane

35 t/h

C4 splitter

Propane

80 t/h

i-Butane

20 t/h

Figure 8: NGL Fractionation with cogeneration


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Reboilers

G

Preheaters

Boiler(s)

5 bar abs

63 bar abs

150C

14 MW

440C

Figure 9: Cogeneration of electrical power and LP steam

High-pressure steam produced in a boiler is used to produce electric power and LP steam. The boiler efficiency ishigh because the water inlet temperature is low. With the same fuel consumption as the reference scheme with a direct-fired hot water heater and the scheme using process heat integration and hot oil, it is possible to produce 14000 kW of

electric power in addition.

Comparison of solutions

Table 9 compares the merits of three configurations that are:

Reference case: No integration and use of hot water for reboiling produced in a direct-fired heater.

Process heat integration (DeC4/C4 Splitter) and use of hot oil for reboiling produced in a direct-fired heater,

Cogeneration.

The options are ranked in Table 9: 1 for the best, 2 for the second, 3 for the last

SchemeNo integration

(Reference)

Processintegration

Cogeneration

Highest column bottom temperature (C) 125 170 125

Heating medium Hot water Hot oil LP steam

Fuel consumption (kW) 88000 88000 88000

Electrical power production (kW) 0 0 14000

Efficiency 2 2 1

CAPEX 1 2 3

OPEX 2 2 1

Operability 2 1 3

Safety 1 3 2

Reliability 2 1 3

Table 9. Comparison of NGL Fractionation Unit Energy Supply Schemes


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Heat recovery from GT exhaust gases

Heat recovery from GT exhaust gases in a Waste Heat Recovery Unit (WHRU) requires the presence of GTs near thefractionation plant. If possible it would be the best solution as process heat is provided with no perhaps zero fuelconsumption.

SchemeNo integration

(Reference)

Processintegration

Cogeneration

1 3 2Table 10: Adaptabilty to use with GT exhaust WHRU

The comparison in Table 9 would remain valid but in this case hot water would be the best heating medium.

Concluding remarks

The increase of the cost of energy makes it necessary to reconsider the cogeneration alternative. Even without gasturbines the cogeneration option is attractive.

PROPANE REFRIGERATION AND ATMOSPHERIC STORAGE

Once extracted, NGL has to be stored before shipment. The C5+ fraction is in most instances stored together withthe stabilized condensate from the inlet separation. Atmospheric storage of stabilized condensate is the standardsolution. Ethane, when extracted, is most frequently sent under gaseous state to the steam cracker.

For small inventories of LPG, pressurized storage may be used, but indisputably, the most delicate storage isrefrigerated storage at atmospheric pressure, required when LPG has to be stored in large quantities. This is the case forLNG Plants, or for large gas treatment plants treating rich feedstock.

In addition to the refrigeration required to compensate for heat ingress through the tanks insulation, chilling must beprovided to cool the LPG before sending it to the tanks.

In this case study, we have considered and compared three options for the cooling of propane run-down and

subsequent storage.

o Closed Loop system with vacuum conditions at the suction of the refrigeration compressor

o Closed Loop system with the refrigeration compressor suction above atmospheric pressure

o Semi-open loop with conditions at the suction of the refrigeration compressor at atmospheric pressure


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Closed Propane refrigeration cycle

Propane

Rundown

160 t/h

Propane

Propane

BOG

Overall Power Consump tion: 5,700 kW

1.3 t/h

0.7 bar

2.4 bar

8.5 bar

Figure 10: Closed propane refrigeration cycle schemeFigure 10 depicts an independent propane cycle that cools down the propane rundown before it is sent to theatmospheric pressure storage tanks. The propane cycle compressor comprises, in most instances, three compressionstages: low, medium and high pressure suction stages. The boil-off of propane from the storage tank is compressed andcondensed, for example, against low-pressure propane. The low pressure stage suction pressure can be below, or aboveatmospheric pressure, depending on the location of the final let-down valve.

Semi-open propane loop

Propane

Rundown

160 t/h

Propane

BOG

Overall Power Consump tion: 5,400 kW

10 t/h

1.0 bar

2.7 bar

8.9 bar

Figure 11: Semi-open propane loop scheme

The concept illustrated in Figure 11 uses the propane run-down itself as the source of refrigerant in a series of kettleexchangers. The entire propane production is vaporized, compressed and condensed. Part of the condensed liquid isrecycled as refrigerant while the remainder, approximately equivalent to the rundown and condensed BOG is chilled andcooled before being sent to the storage tank. The boil-off from the storage tank is mixed with the vapour from the lastchiller and sent to the low-pressure stage of the propane compressor that is naturally operated at atmospheric pressure.

The main advantage of this solution is the cancellation of the previous boil-off gas recovery system and start up fromatmospheric pressure without flaring, thereby leading to a reduction in CAPEX. Such a system has been recentlyimplemented by Technip in an LNG Plant.


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Comparison of solutions

Table 11 ranks the three options against operational and investment criteria.

SchemeCLOSED LOOP

VacuumCLOSED LOOPAtmospheric

SEMI-OPENLOOP

LP C3 Suction Pressure 0.7 bar a 1.2 bar a 1.0 bar a

CAPEX 2 3 1

OPEX 1 1 1

Operability process stability 2 1 2

Operability Availability 3 2 1

Safety 3 1 2

Total 11 8 7

Table 11: Comparison of Refrigeration Schemes for Propane Atmospheric Storage

CONCLUSION

NGL recovery from natural gas is an industry that brings together different processes, types of equipment andmultiple operating constraints. NGL projects require constant innovation and adaptation of technology to solve complexproblems. Although licensed technologies have an important place, the nature of the NGL industry leaves less room forlicensed technologies than in refining or petrochemicals.

An EPC Contractor such as Technip, that has maintained its technical capability to evaluate the consequences of thechoices, has an important role to play at least during the EPC phase. Project execution plans which adopt designcompetition principles up to EPC award are an interesting alternative to the widely used prescriptive FEED route to EPC.Clients that have adopted a design competition approach have obtained improved plant designs with reduced schedules.

A comparison of solutions by EPC contractors under the pressure of competition is the best way to obtain a clear view ofthe situation. Such clients have come to accept that the necessity of competition makes it mandatory to leave somemajor choices open until the end of the design competition.

Success factors in an NGL recovery project

There are many success factors and we do not claim to know all of them. From the experience on NGL recoveryprojects we wish to express some of them that are not obvious:

A good understanding of the Clients objectives and requirements is necessary. It is a starting point to developsolutions. Many options are available, have been used on previous jobs, or are being developed to enhance

profitability.

Understand the requirements: the requirements on the quality of the products are many times expressed in terms ofa minimum specification: for example C2/C3 < 0.01; then nobody wonders about what if C2/C3=0.005; what is thebenefit if any. Many times surpassing the minimum can be easy, not costly and bring far better operability.

Compare solutions using life cycle cost: Whatever the energy cost, the main and best criteria for selection remainsthe minimum overall cost to the operator. The only possibility to bring more resilient solutions back into thecompetition is to make comparisons based on life cycle cost. As large as some gas reserves may seem to be, theyare of course limited and the cost of the feed gas at plant inlet is never negligible.

Operability comes first: Flaring costs a fortune and gives a poor image of the industry; producing less than expected

can jeopardize months of optimisation. It is very difficult to put figures on operability but it is a prime factor that canonly be taken into account by experienced and qualified engineers and plant operators. Today the situation is suchthat managers that have a limited experience of plant operation make decisions that do not take the operabilityfactor with sufficient consideration. The liquefied gases industry is beginning to evaluate the consequences of the


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lack of qualified technical personnel and is trying to find solutions to mitigate the phenomena, at a time when manysenior engineers and operators are leaving or have already left.

Use of new technologies

Of course it is exciting to be a front-runner and often it pays to increase size, efficiency and go for new technologies.Today new technologies are well accepted and it is good news. There is only one factor that shall never be forgotten,it is that the use of new technologies is not an aim it is a means to an end.

In the same way proven technologies are not necessarily old fashioned and shall be allowed to compete as well.

Experience is not frozen knowledge; it is a practically based starting point that can be useful in evaluating newtechnologies.

Methodology

Methodology is of course of prime importance but it has to be specifically defined for each new projects.

Collaboration between Client-Contractor-Suppliers

Collaboration between all the participants: client, contractor and suppliers is a must. Some management techniques

such as team building can help, but good will is the essential ingredient.

During the execution of a contract after the first weeks, difficulties may show up, sometimes it is not very easy tohave the process licensor involved at this stage. Problem solving methods based on a comparison of options similar tothose presented in this paper should be used from the very beginning.

Documents

LPG Recovery Process