COMPARE THE DIFFERENT OPTIONS FOR NGL RECOVERY FROM NATURAL GAS Henri Paradowski Andre Le-Gall & Benoit Laflotte Gas Processing Department Technip, 92973 Paris La Défense, CEDEX France
ABSTRACT As a result of the growth of the natural gas market, worldwide NGL production capacity has increased strongly and continuously in the last decades and this tendency is expected to continue for some years. NGL recovery activity seems to 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 and capital cost. Big improvements have been achieved by moving away from so-called standard practice and through process development studies. There are many options for the different steps of NGL production; in this paper we will compare alternative routes for selected 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. These examples are based on natural gas similar to the Qatar North Field for dehydration and NGL recovery and on an NGL mixture 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.
© Gastech 2005
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 of many 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 projects1 or new capacity additions, therefore providing first-hand access to operating experience. The lessons learnt from past projects 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 distinction should 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 fuel value. The world LPG market has seen a significant market growth in the last decades, with an average growth of 2.9% per year over the past ten years and a current worldwide production of over 210 million tonnes. This average growth is slightly higher than the corresponding growth in natural gas production, and nearly twice the average crude oil production growth. The main drivers for LPG growth worldwide are the residential/commercial sector and uses as petrochemical feedstock, 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 12 compares the average North American spot prices for natural gas (Henry Hub), propane and n-butane (Mount Belvieu). All product prices are referred to their calorific value.
1
“Increasing NGL Plant capacity”, H. Paradowski, L. Barthe and D. Gadelle, GPA European Chapter, Heidelberg Sept. 2003
2
Adapted from EIA / Barnes and Click
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g
p
p
p
Henry Hub / Mount Belvieu monthly spot averages Natural Gas, Propane, n-Butane
10 9
Natural gas 8
Butane
Propane
7 6 5 4
Natural gas
3 2
déc-04
juin-04
sept-04
nov-03
mars-04
mai-03
août-03
janv-03
juil-02
oct-02
avr-02
déc-01
juin-01
sept-01
nov-00
févr-01
mai-00
août-00
janv-00
juil-99
oct-99
déc-98
mars-99
juin-98
sept-98
nov-97
févr-98
avr-97
août-97
janv-97
juil-96
oct-96
déc-95
mars-96
1
Sources: EIA / Barnes and Click
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 market incentive to extract the LPG, except for limited periods of time (winter 2000, winter 2003). More detailed studies indicate that the extraction of LPG in North America3 and in Northern Europe4 show positive margins. This situation translates into significant 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 projects have 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 among others. Additional NGL will be produced in a number of LNG plants that are under implementation or at various project stages.
3
“Uncertainty about gas quality could delay US LNG imports”, D.J. Hawkins , OGJ Sept. 20, 2004
4
“North 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 the reservoir, 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 (glycol dehydration, LPG recovery). More complex feedstock will require additional processing steps and leave room for more complex engineering developments. Typically, optimisation issues are focused around: •
Selection of the acid gas removal process (type of solvent, H2S vs. CO2 selectivity, requirement to remove other sulphur compounds...),
•
Selection of the dehydration technology,
•
Optimisation of the NGL recovery unit to best match the required level of product recovery, flexibility (ethane recovery vs. ethane rejection) and operability constraints,
•
Selection of NGL product purification schemes, including handling of by-products such as disulphide oil in the case of caustic washing of LPG in the liquid phase to remove mercaptans, or regeneration gas handling should gas phase removal of mercaptans be selected.
Such situations are commonly encountered in the Middle East and in the Caspian area, where raw gases are generally wet and sour. Similar situations exist, to a lesser extent in, Africa and South East Asia. All of them pose significant 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-à-vis the export facilities and the targeted market of each of the products. There are few similarities between the issues to be resolved for a straddle plant, located close to a petrochemical complex and a gas treatment plant in a remote producing area, as encountered 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 engineering companies. 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, stabilized condensate, 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:
5
1.
The Wafa Desert Plant pretreats the oil and gas feedstock to allow pipeline transportation to shore where the final extraction and treatment is performed. The options selected for the Wafa Desert Plant are oil and gas condensate stabilisation, CO2 removal, gas dehydration and LPG extraction using a cryogenic process. All liquids are commingled and transported to shore through a 16” pipeline. The sweet gas that has been conditioned for transport (water and hydrocarbon dew-point) is compressed and sent to the coast through a 32” pipeline.
2.
The Mellitah Plant receives gas and condensate separately from the offshore field. Gas is treated to remove H2S and CO2 and is then dehydrated. Part of the LPG is removed and treated. Condensates from the condensate 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 is compressed for export. The liquids from Wafa Desert are fractionated at the Wafa Coastal Plant to yield stabilised crude oil, butane and propane that are shipped separately.
ENI 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 when developing a gas processing plant line-up. We will compare alternative routes, supported with calculations, for the following 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 LSTK projects 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
34°C
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 40,000 kgmole/h
Design Natural gas flow rate
(800 MMSCFD)
Process fluid outlet temperature: air cooled exchangers
34°C
Centrifugal compressor efficiencies
82 %
Air temperature
28°C GE 5 C GE 5 D
Available power for different gas turbines
24,200 kW 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% mole
i-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
33°C
NGL Feed pressure
24 bar abs
NGL Feed flow
245 t/h
Hot 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
440°C
LP Steam pressure
5 bar abs Table 2.2. Other fixed conditions.
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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)
2°C
Table 3.2. Other fixed conditions. 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 the formation of hydrates or to decrease the amount of hydrates formed and the size of the hydrates particles so that the hydrates will not accumulate and plug the equipment. It is known that hydrates formed at very low temperatures in small quantities will not stick to the walls of heat exchangers, valves and other equipment and that they do not plug equipment. It is also known that hydrates can accumulate in dead end zones, where the velocity is reduced. Some devices such as strainers or mesh pads can stop the hydrates crystals and allow a plug to build up. Water content ppm mole
Natural gas at 62 bars
Natural gas at 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
-72
Table 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 from Table 4 that in deep NGL recovery processes where the temperature reaches –100°C it is not possible to avoid the formation of hydrates. However, the quantity that is formed when the water content is 0.1 ppm is extremely small i.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 0.1 ppm 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 the contractor 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 the process design. A short list includes: •
Carry over of liquids, water, hydrocarbons, causing caking of the adsorbent on the upper part of the bed and near the walls of the vessel;
•
Presence of volatile basic compounds in the gas to be dried, these compounds can be production chemicals or 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 will flow 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 of dust, 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 high shear stress;
•
Use simple regeneration sequences with a ramping up of regeneration gas temperature; this will help to avoid 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 using structured packing. The TEG water content is in the range of 0.1 to 0.2 % wt of water. This means that the regeneration 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 an offshore platform. There are some design issues and the contractor shall be familiar with TEG technology to avoid mistakes with potentially 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 melting point of pure TEG is –5°C 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 to defining optimisation guidelines for large NGL recovery trains. The influence of the following parameters on the water content of dry gas has been covered by discrete studies: Lean TEG water content, Natural gas temperature, Number of stages in the TEG absorber,
Natural gas Temperature °C
Number of stages
TEG water content % weight
Dry gas water content 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 water content in the dry gas.
The number of stages and hence the efficiency of the packing selected: this efficiency depends on packing type, 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 the column 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, and C5+ recovery from natural gas. The quantities available have to be such that the cost of infrastructure is not too important. For ethane recovery the situation is complicated because of the absence of a worldwide market for ethane. Many operators have come to the conclusion that ethane recovery does not pay or at best it is seen as a future possibility. In countries where the government has future objectives for an ethane based petrochemical industry, many ERUs have been 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 this choice, the reality of a project including infrastructure is different: ethane recovery has a very significant impact on CAPEX and OPEX. When the recovery of ethane is seen as a future possibility, it is possible to build a propane recovery unit with provisions 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 if not identical features and differ by details. It is the Contractor’s duty to allocate space in the lay out, accessibility, utility connections, etc… © Gastech 2005
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Constant Ethane Production with variable Feed Gas Each case is specific so that it is quite impossible to give the solution. A problem that is met in Europe is that gas usage and production are variable. In winter the demand for gas is high, while in summer it is low. Underground gas storage 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 gas production was expected to fluctuate between winter and summer despite the use of the Lusagnet underground gas storage facility. •
Case study
We studied a similar but hypothetical case where the gas design capacity of the ERU is 800 MMSCFD (see Tables 1.1 and 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 the production of pure C2 is 47.9 t/h in 50t/h of C2+ NGL. With this moderate extraction rate the “Single Reflux Ethane” recovery 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 gas turbine or a VFD electric motor. Now we consider what happens when seasonal variations in gas demand cause variations in feedstock of 600, 700 and 800 MMSCFD for summer, spring and winter respectively. The ethane recovery rate must now be variable and high in 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 during periods of reduced natural gas throughput. The following figures show the main characteristics of the resultant ERU at 800, 700, and 600 MMSCFD. Ethane recovery 72.4% : 47,900 kg/h Power 180 kW.h / t NGL
738 MMSCFD 23,600 kW
7,600 kW
K1
T1
GT
K2
E2
738 MMSCFD
Sales gas 60 bar 34°C 25 bars -94°C
C1 E1
Feed gas
V1 -34°C
60 bar
129,700 kg/h
800 MMSCFD
NGL (C2+)
Figure 3: Single Reflux Ethane recovery process scheme (winter)
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Ethane recovery : 84.8% 49,100 kg/h Power 195 kW.h / t NGL
recycle
641 MMSCFD
Sales gas 60 bar
GT
K2
K1
T1
725 MMSCFD 23,600 kW
84 MMSCFD
7,100 kW
25 bars -99°C
E2
C1 E1
V1
Feed gas
-34°C
60 bar
121,200 kg/h
700 MMSCFD
NGL (C2+)
Figure 4: Dual Reflux Ethane recovery process scheme (spring)
Ethane recovery : 96 % 47650 kg/h Power 215 kW.h / t NGL 6,800 kW
168 MMSCFD
recycle
K1
T1
714 MMSCFD 23,600 kW
GT
K2
546 MMSCFD
Sales gas 60 bar
25 bars -102°C
E2
C1 E1
V1
Feed gas
-34°C
60 bar
109,500 kg/h
600 MMSCFD
NGL (C2+)
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 motor driven compressor. The gas that is recycled cannot be contaminated by seal oil as the compressors use “dry seals”. The contractor, Technip, fit the process to the specific Client (ELF in 1987, TOTAL nowadays after the merger of TOTAL FINA ELF) 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 addition of a vessel V2 makes it possible to increase the ethane recovery rate at constant power consumption. Ethane recovery 88.6 % 51300 kg/h Power 191 kW.h / t NGL
84 MMSCFD
7,100 kW
recycle
GT
K2
K1
T1
724 MMSCFD 23,600 kW
640 MMSCFD
Sales gas 60 bar
25 bars -100°C
E2
C1 E1
V1
Feed gas
-34°C
V2
60 bar
123,400 kg/h
700 MMSCFD
NGL (C2+)
Figure 6: Multiple Reflux Ethane recovery process scheme The MRE process is compared to the DRE process of the late 1980’s 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
kW.h /t NGL
195
191
Specific power consumption
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 no buffer storage. This creates a requirement for variable ethane production, to be adapted to make full use of ethylene plant capacity. The following study therefore considers how to vary ethane recovery while keeping the propane recovery rate at 99% 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-inject excess 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 and increasing 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 and high propane recovery.
Option 1: Reinject C2 into sales gas upstream of the compression
This 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 energy consumption is higher in ethane rejection than in ethane recovery. Today this option would be considered only if distillation of C2+ into C2 and C3+ is integrated in the gas plant and if the amount of excess ethane is low compared to ethane production. •
Option 2: Adjust C2 recovery
This scheme is very simple and easy to operate. It requires only an additional reboiler on the demethanizer. The CAPEX is only slightly higher than an ERU designed only for high ethane recovery. The OPEX is also high: the paradox is that 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 a C2 recovery scheme, it requires additional equipment and valves. CAPEX is higher than an ERU designed only for high ethane recovery. This option has better OPEX than options 1 and 2 and better CAPEX than option 1. There is no decrease of propane production. Today this option is considered on many projects. •
Option 4: Slowly adjust parameters to gradually switch from C2 recovery scheme to C3 recovery scheme
This option is also very simple in principle and robust. Skilled operators and good production scheduling are less critical. Compared to a C2 recovery scheme, it requires additional equipment and valves. The CAPEX is higher than option 3 but it has better OPEX . There is no decrease of propane production. Today this option could be used on projects requiring 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 fractionation columns, 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 90’s and with reference to Tables 2.1 and 2.2 the details are the following: Duty of the reboiler kW
Product flow rate t/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 gas turbine 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 the butane splitter reboiler duty is performed using heat rejected by the debutaniser condenser with trim heating using hot oil.
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C3
Propane 80 t/h
Ethane 65 t/h
i-Butane 20 t/h
integration NGL Feed 245 t/h
Hot oil
Hot oil
Hot oil
Hot oil C5+ 45 t/h
Deethaniser
Depropaniser
Debutaniser
n-Butane 35 t/h
C4 splitter
Figure 7: NGL fractionation with heat integration However, to increase the debutaniser condensing temperature to a useable level the debutaniser pressure and bottom temperature has to be increased with the consequence that hot oil must be used as heating medium instead of hot water. The hot oil temperature has to be relatively high so that the efficiency of the direct-fired heater used to heat the 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 of Figure 7 is abandoned, the scheme becomes that of Figure 8. The temperature of the bottom of the debutaniser column is low, similar to the other columns, so that it is possible to use low-pressure steam from the LP discharge of a steam turbine (Figure 9) used for power generation. C3
Ethane 65 t/h
Propane 80 t/h
LP Steam
LP Steam
i-Butane 20 t/h
NGL Feed 245 t/h
LP Steam
LP Steam C5+ 45 t/h
Deethaniser
Depropaniser
Debutaniser
C4 splitter
Figure 8: NGL Fractionation with cogeneration
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n-Butane 35 t/h
63 bar abs
Boiler(s)
440°C
G 14 MW 150°C Preheaters
5 bar abs
Reboilers
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 is high because the water inlet temperature is low. With the same fuel consumption as the reference scheme with a directfired 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 No integration (Reference)
Process integration
Cogeneration
125
170
125
Hot water
Hot oil
LP steam
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
Scheme Highest column bottom temperature (°C) Heating medium Fuel consumption (kW)
Reliability
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2 1 Table 9. Comparison of NGL Fractionation Unit Energy Supply Schemes
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3
Heat recovery from GT exhaust gases Heat recovery from GT exhaust gases in a Waste Heat Recovery Unit (WHRU) requires the presence of GT’s near the fractionation plant. If possible it would be the best solution as process heat is provided with no perhaps zero fuel consumption. Scheme
No integration (Reference)
Process integration
Cogeneration
1 3 Table 10: Adaptabilty to use with GT exhaust WHRU
2
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 gas turbines 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 with the stabilized condensate from the inlet separation. Atmospheric storage of stabilized condensate is the standard solution. 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 is refrigerated storage at atmospheric pressure, required when LPG has to be stored in large quantities. This is the case for LNG Plants, or for large gas treatment plants treating rich feedstock. In addition to the refrigeration required to compensate for heat ingress through the tank’s insulation, chilling must be provided 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
Overall Power Consumption: 5,700 kW
Propane
Propane BOG
8.5 bar 2.4 bar
1.3 t/h 0.7 bar
Propane Rundown 160 t/h
Figure 10: Closed propane refrigeration cycle scheme Figure 10 depicts an independent propane cycle that cools down the propane rundown before it is sent to the atmospheric pressure storage tanks. The propane cycle compressor comprises, in most instances, three compression stages: low, medium and high pressure suction stages. The boil-off of propane from the storage tank is compressed and condensed, for example, against low-pressure propane. The low pressure stage suction pressure can be below, or above atmospheric pressure, depending on the location of the final let-down valve. Semi-open propane loop
Overall Power Consumption: 5,400 kW
Propane BOG
8.9 bar 2.7 bar
10 t/h 1.0 bar
Propane Rundown 160 t/h
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 kettle exchangers. The entire propane production is vaporized, compressed and condensed. Part of the condensed liquid is recycled as refrigerant while the remainder, approximately equivalent to the rundown and condensed BOG is chilled and cooled before being sent to the storage tank. The boil-off from the storage tank is mixed with the vapour from the last chiller 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 from atmospheric pressure without flaring, thereby leading to a reduction in CAPEX. Such a system has been recently implemented by Technip in an LNG Plant. © Gastech 2005
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Comparison of solutions Table 11 ranks the three options against operational and investment criteria. CLOSED LOOP Vacuum
CLOSED LOOP Atmospheric
SEMI-OPEN LOOP
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
Scheme LP C3 Suction Pressure
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 and multiple operating constraints. NGL projects require constant innovation and adaptation of technology to solve complex problems. Although licensed technologies have an important place, the nature of the NGL industry leaves less room for licensed technologies than in refining or petrochemicals. An EPC Contractor such as Technip, that has maintained its technical capability to evaluate the consequences of the choices, has an important role to play at least during the EPC phase. Project execution plans which adopt design competition 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 of the situation. Such clients have come to accept that the necessity of competition makes it mandatory to leave some major 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 recovery projects we wish to express some of them that are not obvious: •
A good understanding of the Client’s objectives and requirements is necessary. It is a starting point to develop solutions. 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 of a minimum specification: for example C2/C3 < 0.01; then nobody wonders about what if C2/C3=0.005; what is the benefit 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 remains the minimum overall cost to the operator. The only possibility to bring more resilient solutions back into the competition is to make comparisons based on life cycle cost. As large as some gas reserves may seem to be, they are 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 can only be taken into account by experienced and qualified engineers and plant operators. Today the situation is such that managers that have a limited experience of plant operation make decisions that do not take the operability factor 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 many senior 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 new technologies.
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 to have the process licensor involved at this stage. Problem solving methods based on a comparison of options similar to those presented in this paper should be used from the very beginning.
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