NATURAL GAS QUALITY SPECIFICATIONS AND LNG SUPPLY...
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NATURAL GAS QUALITY SPECIFICATIONS AND LNG SUPPLY End user market will have to adapt to new energy sources Tore Løland 1 1. StatoilHydro Keywords: 1. LNG; 2. Gas Quality; 3. Harmonization 1 Introduction/Background Natural gas has been one of the major energy carriers for more than 100 years. In the beginning, the gas was supplied from local domestic sources, but as the need for energy increased, the supplies came from further away. The split between several different sources increased the challenges with respect to gas quality, and pipeline blending and mixing became a bigger and bigger issue. Today, mixing is often needed to fulfil the requirements or account for the limitations of the infrastructure. The US and European markets have to some extent developed differently with respect to gas quality, with the US being the leanest one. One of the reasons for this is the use of LNG peak shaving facilities for seasonal swing, and the fact that the domestic sources have been leaner in the US, than the supplies from the north, east and south to Europe. In Europe large pipelines along with underground storage has been used to meet the peak demand. It is well known that LNG is cold and liquefied Natural Gas, but it is sometimes forgotten that there is a difference between the traditional natural gas supplied to the end-user, and LNG when speaking of gas quality. LNG is natural gas cooled to -163°C, but to be able to cool down the natural gas, some vital changes has to be made; otherwise freeze-out will occur during the liquefaction process. Even if the first overseas LNG cargo did go from the US to UK, and the first cargo from a base load LNG plant went from Algeria to the UK, the largest consumers of LNG has historically been Asia, and especially Japan. In Europe LNG was introduced more than 40 years ago, but in terms of volume LNG has always been marginal compared to pipeline gas. In the US, LNG has been used for peak shaving during the winter season and small scale LNG is therefore common in highly populated areas. Base load LNG and peak shaving LNG has developed differently seen from a gas quality point of view. In the US, the feed to the peak shavers is the same as the pipeline gas. The only processing done is to remove some heavier hydrocarbons (HC), 2 CO and water that will freeze out during cool down. This type of processing will only have minor effect on the heating value of the gas as long as pipeline gas is lean. Base load LNG has primarily been used by countries that do not have a domestic gas supply and for them the main focus when using LNG has been to maximize the energy content in each cargo. In general the different markets have developed differently due to historical circumstances, and this is the basis for the difference in gas quality around the world. Several articles [1],[2] have been presented over the years about development of different technologies for base load LNG, equipment size, cold versus hot climate, power consumption, flexibility with respect to turndown and sensitivity of feed to the plant. From the end users point of view this is of minor interest. For them, the main focus will be the difference between LNG and the existing domestic gas supply. The effect will be independent of LNG technology as all technologies in use can be designed to produce different LNG qualities. The financial crisis has shown that a flexible market is needed. If not, it will be come more difficult for the producers to take the large capital risks for investing in new plants. At the same time it has becomes harder for the producers to get financing for new projects. Harmonization of the world wide gas quality spec will be an important factor in reducing the risk.
Transcript of NATURAL GAS QUALITY SPECIFICATIONS AND LNG SUPPLY...
NATURAL GAS QUALITY SPECIFICATIONS AND LNG SUPPLY End user market will have to adapt to new energy sources
Tore Løland
1
1. StatoilHydro
Keywords: 1. LNG; 2. Gas Quality; 3. Harmonization 1 Introduction/Background Natural gas has been one of the major energy carriers for more than 100 years. In the beginning, the gas was supplied from local domestic sources, but as the need for energy increased, the supplies came from further away. The split between several different sources increased the challenges with respect to gas quality, and pipeline blending and mixing became a bigger and bigger issue. Today, mixing is often needed to fulfil the requirements or account for the limitations of the infrastructure. The US and European markets have to some extent developed differently with respect to gas quality, with the US being the leanest one. One of the reasons for this is the use of LNG peak shaving facilities for seasonal swing, and the fact that the domestic sources have been leaner in the US, than the supplies from the north, east and south to Europe. In Europe large pipelines along with underground storage has been used to meet the peak demand. It is well known that LNG is cold and liquefied Natural Gas, but it is sometimes forgotten that there is a difference between the traditional natural gas supplied to the end-user, and LNG when speaking of gas quality. LNG is natural gas cooled to -163°C, but to be able to cool down the natural gas, some vital changes has to be made; otherwise freeze-out will occur during the liquefaction process. Even if the first overseas LNG cargo did go from the US to UK, and the first cargo from a base load LNG plant went from Algeria to the UK, the largest consumers of LNG has historically been Asia, and especially Japan. In Europe LNG was introduced more than 40 years ago, but in terms of volume LNG has always been marginal compared to pipeline gas. In the US, LNG has been used for peak shaving during the winter season and small scale LNG is therefore common in highly populated areas. Base load LNG and peak shaving LNG has developed differently seen from a gas quality point of view. In the US, the feed to the peak shavers is the same as the pipeline gas. The only processing done is to remove
some heavier hydrocarbons (HC), 2CO and water that will freeze out during cool down. This type of
processing will only have minor effect on the heating value of the gas as long as pipeline gas is lean. Base load LNG has primarily been used by countries that do not have a domestic gas supply and for them the main focus when using LNG has been to maximize the energy content in each cargo. In general the different markets have developed differently due to historical circumstances, and this is the basis for the difference in gas quality around the world. Several articles [1],[2] have been presented over the years about development of different technologies for base load LNG, equipment size, cold versus hot climate, power consumption, flexibility with respect to turndown and sensitivity of feed to the plant. From the end users point of view this is of minor interest. For them, the main focus will be the difference between LNG and the existing domestic gas supply. The effect will be independent of LNG technology as all technologies in use can be designed to produce different LNG qualities. The financial crisis has shown that a flexible market is needed. If not, it will be come more difficult for the producers to take the large capital risks for investing in new plants. At the same time it has becomes harder for the producers to get financing for new projects. Harmonization of the world wide gas quality spec will be an important factor in reducing the risk.
2 StatoilHydro’s position
StatoilHydro started investigating LNG solutions more than 25 years ago when natural gas was discovered at the Snøhvit field in the Barents Sea, see Figure 1. The Snøhvit field is located at 71 degrees north, and an LNG solution was selected due to the lack of pipeline infrastructure. During the years, several development suggestions for an LNG plant for Snøhvit was put forward, but it was only until the late 1990s that the development was finalized through an approval by the Norwegian authorities.
3.26%Amerada Hess Norge AS
2.81%RWE Dea Norge AS
12.00%Gaz de France Norge AS
18.40%Total E&P Norge AS
30.00%Petoro AS
33.53%Statoil ASA (Operator)
• Water depth: 250 – 340 m
• Distance to shore: 140 km
• Condensate: 34 MSm3
• Gas in place (GIIP): 317 GSm3 or 11.2 TCF
• Owners:
3.26%Amerada Hess Norge AS
2.81%RWE Dea Norge AS
12.00%Gaz de France Norge AS
18.40%Total E&P Norge AS
30.00%Petoro AS
33.53%Statoil ASA (Operator)
• Water depth: 250 – 340 m
• Distance to shore: 140 km
• Condensate: 34 MSm3
• Gas in place (GIIP): 317 GSm3 or 11.2 TCF
• Owners:
Figure 1 - The Snøhvit Field
As a National Oil Company, StatoilHydro has been a driver for development of new technology. The multiphase flow simulator OLGA, the submerged turret technology APL, multiphase metering and thermodynamic property tools such as STEP (basis for PVTSim by Calsep) are technologies that StatoilHydro has participated in development of. Also LNG technology and cryogenic heat exchanger design has been developed by StatoilHydro and its partners during the past 30 years. StatoilHydro’s involvement in development LNG technology was terminated by the introduction of a new
liquefaction process installed at the Hammerfest LNG plant, known as the MFC (Mixed Fluid Cascade) technology. Today StatoilHydro is operating across the whole LNG chain, from field to market. We are operating the arctic base load LNG plant in Hammerfest, the world most northerly LNG plant. We have access to 1.1 bcfd of regas capacity at the Cove point terminal at the US East Cost. We have our own marketing and selling company for the US market, and trade 3rd party LNG into the US market. In addition, StatoilHydro has acquired a 32.5% interest in Chesapeake’s Marcellus shale gas acreage covering 1.8 million net acres (7,300 square kilometres) in the Appalachian region of the US North East. Further StatoilHydro has been one of the leading companies for the last 20 years of development of Floating LNG (FLNG) technology. We have been involved in the development of heat exchangers, liquefaction technologies and off loadings systems for FLNG. StatoilHydro has during many years supported work on gas quality, both in the US, Europe as well as the international activities for harmonisation of gas quality. StatoilHydro has supported work done by IGU, GERG and EASEEGAS because we do think that a common technical understanding is needed between seller and buyer of natural gas. Common understanding of the
limitations and the effects of gas quality models are needed as the margins with respect to limits in the gas quality specifications get smaller and smaller. Not only is this an issue between seller and buyer, and governmental regulations and requirements have become more and more important as focus on global warming has increased.
3 Process
For base load LNG production the feed gas pre-treatment will be similar for a wide range of feeds. 2CO ,
water and mercury will have to be removed completely (to 50 ppm 2CO and 1 ppm water). This is generally
done in the same way for all base load LNG plants around the world.
2N is always reduced to a level below the limit for roll over, generally 1 mol%. During design, the 1% limit is
normally used, but in operation this can be somewhat increased, since rollover is a minor problem for the upstream production due to the short storage time. Setting the Gross Calorific Value (GCV) for the LNG is an issue for the process engineer when doing the design. The pressure and temperature in the heavy hydrocarbon (HHC) column will decide the split between the part going to cool down, and the rest going to fractionation. How this is integrated in the liquefaction process will depend both on the design philosophy and on the technology used, but this is in general straight forward for all of the available LNG technologies.
Figure 2 shows the 2CO , water and mercury removal sequence along with integrated or separate NGL
recovery typical for most LNG technologies.
Condensate
treatment
Pre cooling/
Liquefaction/
Sub cooling
LNG storage
LPG storage
Condensate
storage
FractionationRefrigerant
makeup
Nitrogen
removal
Nitrogen
CO2 (and H2S)
LNG
LPG
Condensate
Inlet facilities Mercury
removal
Acid gas
treating
Dehydration
Alt. for
fuel gas
take off
MercuryWater
Feed NGL
Recovery
Alt. for fuel
gas take off
Merged if HHC removal is
integrated with Liquefaction
Condensate
treatment
Pre cooling/
Liquefaction/
Sub cooling
LNG storage
LPG storage
Condensate
storage
FractionationRefrigerant
makeup
Nitrogen
removal
Nitrogen
CO2 (and H2S)
LNG
LPG
Condensate
Inlet facilities Mercury
removal
Acid gas
treating
Dehydration
Alt. for
fuel gas
take off
MercuryWater
Feed NGL
Recovery
Alt. for fuel
gas take off
Merged if HHC removal is
integrated with Liquefaction
Figure 2 - Typical LNG process lay-out
4 Environmental issues
New and stricter environmental regulations will affect the design for LNG liquefaction plant. Traditionally, all technologies have used end flash as fuel gas, along with boil off gas (BOG) from the storage tanks. Normally the BOG returned form from the ships during loading has been flared. This design has generally been independent of LNG liquefaction technology. In the future, more focus will be given to environmental pollution. Focus will be both on local environmental
issues, likeX
NO , as well as on global warming, like 2CO .
More than 183 countries1 around the world have signed the Kyoto protocol, and have agreed to reduce the
emission of 2CO , as well as local emission sources. This will affect the handling of both the end flash as well
as the boil off from storage and loading. It is a challenge for the process engineer to include both the requirements from the gas turbine vendors with respect to specifications and stability in the composition of the fuel, as well as reducing the flaring to an absolute minimum.
The gas turbine drives will need a steady feed for keeping theX
NO levels down, this means that the end
flash no longer can be used for fuel untreated. New burner designs in the gas turbines are very strict on variations in the composition of the fuel, as well as
high levels 2N . Variations in the process will give variations in the subcooled natural gas outlet temperature,
which again will affect the composition of the end flash. Theoretically speaking, both the end flash as well as the boil off gas from the storage tanks, can be regarded as stable, but experience from operations show that
• The natural gas temperature out of the subcooler can vary. This affects the composition of end flash.
• The ambient temperature and pressure will vary. This makes the amount of boil off gas generated from storage vary.
Unlike the end user market, an LNG plant will see more rapid changes especially when the boil off gas compressor starts or stops. At the end user, monitoring of the natural gas can be done at several junctions upstream, and warnings can be provided, and blending actions can reduce the effect. Inside an LNG plant this is not possible. In addition, new regulations regarding boil off gas handling during ship loading will become an issue. Start and stop of ship loading will affect the fuel composition if the return gas is linked to the same fuel gas system. The process engineer doing the design of the plant will have to think about operational stability as well as flexibility when doing the design. Gas turbines have become more sensitive to changes in the fuel [3],[4]. In the LNG plant, the fuel for the gas turbines will have to be treated or moved upstream. Both methods will lead to a more stable fuel quality, but will in general require more investments as well as consume more
power. To reduce pollution, the end flash gas will have to be stripped for 2N in order to recover the methane,
which again will lead to higher power consumption and investments. Many of the same effects can be seen in downstream power production as well, the stricter environmental regulations will require more stable gas quality. It is however important to understand the difference between the upstream and downstream gas quality issues. It will always be a trade of between availability, price for energy and environmental pollution. In the future, gas quality will play an important role, and seen from a technical point of view, harmonization of the gas quality is the only way forward. In a market where the gas quality deviates from the rest of the world, the end user will have to pay a higher price for the gas than elsewhere.
5 A case study
For general tariff discussions it is of vital importance to use well known international standards and open public data sources. In this way any chosen set-point in the tariff will be traceable for all involved parties as well as any governmental body. As an example, this paper will give highlights from a case study that StatoilHydro did as a part of the gas quality discussions taking place for several pipelines in the North East of the US. StatoilHydro has considerable experience from operation and control of gas pipeline systems. Norway is supplying 20% of the natural gas needed in Europe, see Figure 3. Approximately 80% of this is sold by StatoilHydro on behalf of the Norwegian government and the company itself.
1 As of February 2009
We wanted to use our experience and knowledge about LNG and pipeline export, to focus on the effect of supply with respect to gas quality limits.
Nyhamna
Europipe II
Europipe I
Norpipe
Emden
Teesside
ÅTS
Norne
Åsgard
Haltenpipe
Heidrun
Franpipe
Zeebrugge
Zeepipe I
St Fergus
Vesterled
Frigg
Statfjord
Kårstø
Kollsnes
Melkøya
Snøhvit
Ormen Lange
Easington
Langeled
Ekofisk
Sleipner
Troll
Dunkerque
Kristin
NyhamnaNyhamna
Europipe IIEuropipe IIEuropipe II
Europipe IEuropipe I
Norpipe
Emden
TeessideNorpipe
Emden
NorpipeNorpipeNorpipe
EmdenEmden
TeessideTeessideTeesside
ÅTSÅTS
Norne
Åsgard
Haltenpipe
Heidrun
Norne
Åsgard
Haltenpipe
Heidrun
FranpipeFranpipe
Zeebrugge
Zeepipe I
ZeebruggeZeebrugge
Zeepipe I
St Fergus
Vesterled
St Fergus
Vesterled
FriggFrigg
StatfjordStatfjord
KårstøKårstø
KollsnesKollsnes
MelkøyaMelkøya
SnøhvitSnøhvit
Ormen LangeOrmen Lange
Easington
Langeled
Easington
Langeled
EkofiskEkofisk
SleipnerSleipner
TrollTroll
Dunkerque
Kristin
Figure 3 - The Norwegian gas transport system to Europe
Today’s sources of LNG in the world are limited, partly due to the fact that investments for LNG plants are large. In addition the long lead time from sanction to start of production makes it easy to foresee the maximum potential future growth. The quality of the actual loaded LNG and the contractual quality of LNG is normally not public information. In addition there might be individual variations due to:
• Seasonal changes
• Ageing of the driver gas turbines
• Fouling of refrigerant heat exchangers or other heat exchangers
• It is also a fact that for the major part of the LNG production plants built during the last 20 – 30 years, the nameplate capacity was much less that the actual capacity due to design safety margins
In general available data like the Wood Mackenzie data [5] can be used as a basis for analysis giving valuable information in tariff discussions like the ones taking place in the US North East. The data gives information about loaded heating value, for plants in operation, under construction as well as for planned base load LNG plants. In the work some assumptions were made.
The first assumption was 1mol% 2N in the LNG rundown to storage. Compensated for ageing, the 2N level
after approx 10 days of travelling would be in the range of 0.7 mol% 2N .
A simple sensitivity analysis used on different lean gas qualities like the ones used in the US North East
show that a ±0.15mol% on 2N would not make much difference to the overall result.
Actually, a reduction in the 2N level during production below 1 mol% would lead to reduced production due to
higher subcooler outlet temperature. This will increase the heating value along with reducing 2N , since more
1C as well as 2N would be leaving in the end flash gas.
The ship transport will affect the heating value of the LNG. In general, we can assume that the LNG is at equilibrium when leaving the base load LNG plant. Many factors will affect ageing (the increasing of the heating value) during the travel. Factors like: Type of LNG ship, age of LNG ship, distance to travel and time of year or sea conditions will affect the actual increase in heating value. Looking at the world map, most of the base load LNG plants are located at a distance from the market that can fit with approximately 10 days of travel. For simplicity we have assumed 10 Btu/Scf increase in GCV to compensate for ageing. This is based on a 10 days travel using 0.2%/day in boil off rate. This is a simplification based on experience, used to avoid usage of non-public tools and specific ship information. The data from Wood Mackenzie
2 was shifted to account for the ageing during transport. Further,
the 2N content at receiving terminal was adjusted to 0.7 mol%.
In the work we decided to divide the LNG production into 3 groups 1. Group 1 – This would comply with the end user requirements under all circumstances 2. Group 2 – This can be regarded as the intermediate group 3. Group 3 – This would never comply with end user requirements without further removal of heavier
HC or blending. For the critical plants at the boundary of each group, we used information about the GCV and Wobbe Index (WI), and adjusted the composition to fit with the new GCV at the receiving terminal. The adjustment was done based on a general knowledge about component proportion in a scrub column operating at 50bara and approx -25°C. The final fit for each composition was done manually trying to keep the component split close
to the original one, with some more reduction in 1C than in +3C .
The first group will always be able to meet the spec proposed for the North East. This means that the LNG loaded at the base load LNG plant will have an upper limit of about 1100 Btu/Scf, giving a landed LNG the US North East at about 1110 Btu/Scf. As of today’s production this means that group 1 (see Table 1) will be in the range of about 30% of the world LNG production. In 2015 this share will have increased to about 42%. For group 3 (see Table 2) the loaded heating value is 1127 or more. This group will never be landed in the US North East without further processing or blending with other sources. The GCV is too high for only
blending with 2N or other non combustible components.
This is about 26% of the world production, and will decrease to about 20% in 2015. The remaining part of the world’s supply (see Table 3) is the one that will be affected by the tariff settings for
both +3C and non combustible components like 2N . This group is characterized by a heating value between
1107 and 1124 Btu/Scf at the base load plant.
I.e. the 2N level set in the tariff will directly affect the part of this group can be landed in the North East area.
The group 2 will be in the range of 40% of the world supply for the next 7 to 8 years.
Depending on the starting point and travel time, the need for 2N injection will be in the range of 1 to 4%.
At some point during the discussions a proposed upper limit of 2.3mol% was given for 2N . Using this limit,
Arun and Bontang will make it, since only 2.2mol% 2N will be needed to meet the proposed GCV spec.
Plants like NLNG, Angola, Brass and OK will most likely require 3.5mol% 2N , thus exceeding the upper limit.
Looking at the world production, NLNG, Angola, Brass and OK LNG represent 17% of global supplies of LNG. Setting a tight limit like 2.3 mol% would have left out a major part of the world production since all of group 3 and almost 50% of group 2 would not make it with this tariff spec.
2 Data presented are from the 2007 version of Wood Mackenzie database. Minor changes to current status of database
may occur due to updated production profiles and stopped projects.
41.5%44.7%30.1%21.0%Percentages
141.4119.254.629.0Totals
3.43.43.40.111101100OmanQalhat LNG
7.17.17.17.111101100OmanOLNG
6.76.40.00.010851075YemenYemen LNG
4.24.20.90.010851075NorwaySnohvit
4.51.90.00.010851075PeruPeru LNG
3.73.71.60.010851075Equatorial GuineaEG LNG
3.23.23.20.010851075AustraliaDarwin
15.615.60.00.010801070QatarRL 3
7.83.30.00.010801070QatarQatargas-4
7.87.20.00.010801070QatarQatargas-3
15.615.60.00.010801070QatarQatargas-2
4.00.00.00.010801070AlgeriaGassi Touil
10.00.00.00.010751065AustraliaGorgon
12.612.610.35.210681058AlgeriaAlgeria LNG
7.67.40.00.010501040IndonesiaTangguh
3.63.63.60.710501040EgyptELNG 2
3.63.63.61.810501040EgyptELNG 1
5.15.15.12.710501040EgyptDamietta
5.25.24.40.010411031TrinidadAtlantic LNG 4
3.43.43.43.410411031TrinidadAtlantic LNG 3
3.43.43.43.410411031TrinidadAtlantic LNG 2
3.33.33.33.310411031TrinidadAtlantic LNG 1
0.00.01.31.310191009United StatesKenai
Project CountryLoaded GCV
(Btu/scf)
Landed GCV
(+10 Btu/scf)
Volumes (mmtpa)
2005 2007 2010 2015
41.5%44.7%30.1%21.0%Percentages
141.4119.254.629.0Totals
3.43.43.40.111101100OmanQalhat LNG
7.17.17.17.111101100OmanOLNG
6.76.40.00.010851075YemenYemen LNG
4.24.20.90.010851075NorwaySnohvit
4.51.90.00.010851075PeruPeru LNG
3.73.71.60.010851075Equatorial GuineaEG LNG
3.23.23.20.010851075AustraliaDarwin
15.615.60.00.010801070QatarRL 3
7.83.30.00.010801070QatarQatargas-4
7.87.20.00.010801070QatarQatargas-3
15.615.60.00.010801070QatarQatargas-2
4.00.00.00.010801070AlgeriaGassi Touil
10.00.00.00.010751065AustraliaGorgon
12.612.610.35.210681058AlgeriaAlgeria LNG
7.67.40.00.010501040IndonesiaTangguh
3.63.63.60.710501040EgyptELNG 2
3.63.63.61.810501040EgyptELNG 1
5.15.15.12.710501040EgyptDamietta
5.25.24.40.010411031TrinidadAtlantic LNG 4
3.43.43.43.410411031TrinidadAtlantic LNG 3
3.43.43.43.410411031TrinidadAtlantic LNG 2
3.33.33.33.310411031TrinidadAtlantic LNG 1
0.00.01.31.310191009United StatesKenai
Project CountryLoaded GCV
(Btu/scf)
Landed GCV
(+10 Btu/scf)
Volumes (mmtpa)
2005 2007 2010 2015
Table 1 - Group 1 LNG Producers
20.0%23.6%26.5%34.9%Percentages
68.363.148.148.1Totals
0.70.70.70.711701160LibyaMarsa El Brega
7.27.27.27.211701160BruneiBrunei LNG
9.69.40.00.011601150RussiaSakhalin 2
6.86.86.86.811431133MalaysiaMLNG Tiga
9.09.07.87.811431133MalaysiaMLNG Dua
8.18.18.18.111431133MalaysiaMLNG
5.00.00.00.011371127AustraliaPluto
16.316.311.911.911371127AustraliaNorth West Shelf
5.65.65.65.611371127Abu DhabiADGAS
Project Country
Loaded GCV (Btu/scf)
Landed GCV (+10 Btu/scf)
Volumes (mmtpa)
2005 2007 2010 2015
20.0%23.6%26.5%34.9%Percentages
68.363.148.148.1Totals
0.70.70.70.711701160LibyaMarsa El Brega
7.27.27.27.211701160BruneiBrunei LNG
9.69.40.00.011601150RussiaSakhalin 2
6.86.86.86.811431133MalaysiaMLNG Tiga
9.09.07.87.811431133MalaysiaMLNG Dua
8.18.18.18.111431133MalaysiaMLNG
5.00.00.00.011371127AustraliaPluto
16.316.311.911.911371127AustraliaNorth West Shelf
5.65.65.65.611371127Abu DhabiADGAS
Project Country
Loaded GCV (Btu/scf)
Landed GCV (+10 Btu/scf)
Volumes (mmtpa)
2005 2007 2010 2015
Table 2 - Group 3 LNG producers
38.5%31.7%43.4%44.1%Percentages
131.284.678.860.8Totals
14.114.114.15.911341124QatarRasGas II
6.66.66.66.611341124QatarRasGas
9.79.79.78.811341124QatarQatargas
12.512.510.35.111311121AlgeriaAlgeria LNG
22.00.00.00.011251115NigeriaOK LNG
10.00.00.00.011251115NigeriaBrass LNG
5.00.00.00.011251115AngolaAngola LNG
8.40.00.00.011241114NigeriaNLNG Seven Plus
8.18.18.10.011241114NigeriaNLNG Plus
3.33.33.33.311241114NigeriaNLNG Expansion
6.76.76.76.711241114NigeriaNLNG Base
4.14.10.90.011241114NigeriaNLNG 6
20.718.417.020.111171107IndonesiaBontang
0.01.12.14.311171107IndonesiaArun
Volumes (mmtpa)Project Country
Loaded GCV (Btu/scf)
Landed GCV (+10 Btu/scf) 2005 2007 2010 2015
38.5%31.7%43.4%44.1%Percentages
131.284.678.860.8Totals
14.114.114.15.911341124QatarRasGas II
6.66.66.66.611341124QatarRasGas
9.79.79.78.811341124QatarQatargas
12.512.510.35.111311121AlgeriaAlgeria LNG
22.00.00.00.011251115NigeriaOK LNG
10.00.00.00.011251115NigeriaBrass LNG
5.00.00.00.011251115AngolaAngola LNG
8.40.00.00.011241114NigeriaNLNG Seven Plus
8.18.18.10.011241114NigeriaNLNG Plus
3.33.33.33.311241114NigeriaNLNG Expansion
6.76.76.76.711241114NigeriaNLNG Base
4.14.10.90.011241114NigeriaNLNG 6
20.718.417.020.111171107IndonesiaBontang
0.01.12.14.311171107IndonesiaArun
Volumes (mmtpa)Project Country
Loaded GCV (Btu/scf)
Landed GCV (+10 Btu/scf) 2005 2007 2010 2015
Project CountryLoaded GCV
(Btu/scf)
Landed GCV (+10 Btu/scf) 2005 2007 2010 2015
Table 3 - Group 2 LNG producers
In general, a simple analysis like this one can give valuable information about the consequence of the different limits set in the tariff. Any tariff discussions must include
• Availability of natural gas
• Technical limitations with respect to gas processing and liquefaction plant design. Deep cuts giving lower heating value is generally more expensive in terms of power need and investments.
• The new an increased focus on environmental issues.
• Large spread in tariff between different markets. It is difficult to align downstream markets with large variations, and the work done by IGU and others is very important in this respect. Further the harmonisation in Europe has shown that it is very difficult to open up and liberalize the European gas market. Narrowing the tariff will not open up for any new supply, whether it is LNG from a broad range of plants, or it is unconventional domestic sources, like shale gas in the US. Seen from our point of view the end user must in the future balance between availability of energy, environmental regulations and the price. In some areas changes to the infrastructure are unavoidable, and that i.e. the US North East will have to adapt to the new situation by adjusting the infrastructure, or pay more for the gas. In the long run changes to the infrastructure will be the least expensive.
6 Conclusion
Technically speaking there are very few limitations for solving the issues of LNG quality. The producers can normally design and operate the process to fulfil all types of qualities, but a decision of which quality to produce will have to be made before sanction, lean or rich.
There are a few important technical limitations for LNG; 2CO , water and the heavier hydrocarbons will freeze
out. It is therefore essential to remove these before cool down. The end user market will have to take these issues into account when discussing local gas quality issues. Tailor making of the LNG quality will have some limitations technically, but in general it is an economical question seen from a producer’s point of view. After sanction it is economically impossible to impose large changes in the LNG quality, unless the tank farm is so big that mixing from different trains can be performed, but this again will generally lead to extra boil off.
Due to the extremely high investment costs, the LNG producers will secure the highest possible “rate of return” of the investments before sanction of the project. End user market is one of the factors affecting the sanction decision. If the cost for delivering the LNG increases, the producer will turn to another market. The Hammerfest LNG plant operated by StatoilHydro have been designed to fit both the European and the US market, and we very much support the ongoing work of harmonization of the world wide LNG quality, as done by the IGC. However, if the end user establishes too many local restrictions, and the harmonization gets too many local variations, this will be harmful for the availability in that specific part of the market. Strict local regulations may turn a project from profitable to uneconomical, and the producer will have to look for other possibilities if the reserves are to be developed. In many cases LNG maybe one of very few alternative methods for exporting the HC resources from a field. The present situation with a financial crisis does not change the overall picture seen from our point of view, as this must be regarded as a short term issue both for the producer and end user. In addition the financial crisis actually has strengthened the need for the producer to reduce cost, and this will increase the focus on the issues described in the present paper. References [1] M.Pillarella, Y.Liu, J.Petrowski and R.Bower. “The C3MR Liquefaction Cycle: Versatility for a Fast
Growing, Ever Changing LNG Industry”. LNG 15 – Barcelona (Spain), April 2007 [2] P.Bosma, R.K.Nagelvoort. “Liquefaction technology; Development through History”. 1
st Annual
Processing Symposium – Doha (Qatar), January 2009. [3] J.Zachary. “New Challenges for Combined Cycle Plants – Pushing the Envelope”. Power Gen
Europe. Cologne (Germany), May 2009. [4] B.Prade, P.Berenbrink, B.Köstlin. “Siemens Gas Turbines with High Fuel Flexibility on Natural Gases”. Power Gen
Europe. Cologne (Germany), May 2009.
[5] http://www.woodmac.com/energy
