Lindi to host $30b LNG plant, but land issues may provoke protests; The Land now belongs to METL

Lindi to host $30b LNG plant, but land issues may provoke protests; The Land now belongs to METL

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Investors select Likong'o-Michinga area as best site for $30 billion plant, leaving Mtwara in the cold. TEA Graphic

By ERIC KABENDERA Special Correspondent

Posted Saturday, March 29 2014 at 18:29
IN SUMMARY

  • The firms selected the area as the best location for the $30 billion project following a request by the government for companies to evaluate viable site options for building an onshore LNG plant.
  • Decision to build the LNG plant in Lindi may not go down well with the residents of Mtwara region as the government had promised them that the plant would be built in their area to promote economic growth.
  • Industry analysts fear that the chosen 6,800-acre site, which will have an LNG plant on 2,000 acres, and an industrial park, could lead to a dispute between the owner of the land and the government as the Lands Ministry embarks on invalidating the title deed.

Tanzania's first liquefied natural gas plant will be located at Likong'o–Mchinga in the southern town of Lindi if the decision of Statoil AS and BG Group Plc is upheld.

The firms selected the area as the best location for the $30 billion project following a request by the government for companies to evaluate viable site options for building an onshore LNG plant.

But the decision to build the LNG plant in Lindi may not go down well with the residents of Mtwara region. In June last year, the government promised Mtwara residents that the plant would be built in their area to promote economic growth.

The residents had protested against a proposed state-owned project to construct a $1.2 billion 524km gas pipeline from Mtwara to Dar es Salaam.

According to Subiro Mwapinga, an independent oil and gas consultant, selecting Lindi may provoke fresh riots, although oil and gas companies would still use Mtwara as the supply base.

"The government promised to build so many things but most of them are not feasible. For example, the government doesn't have resources to build ports in both Mtwara and Lindi," he said.

Some 30 sites were considered for the LNG plant project.

Before the government asked the partners to develop the plant, Statoil had selected Rushungi but its partners chose Likong'o.

Industry analysts fear that the chosen 6,800-acre site, which will have an LNG plant on 2,000 acres, and an industrial park, could lead to a dispute between the owner of the land and the government as the Lands Ministry embarks on invalidating the title deed.

The ownership will be moved to the Tanzania Petroleum Development Corporation (TPDC) on behalf of the stakeholders, who include the government. On Thursday, TPDC signed a memorandum of understanding that gives the government the responsibility of securing the land.

Sources said the process of acquiring the land had stalled the project for six months, a delay which may affect investors' confidence.

The plant will receive and treat reservoir gas from the fields in blocks 1, 2, 3 and 4, where discovery of 45 trillion cubic feet (tcf) of natural gas in massive deep offshore waters was made.

Further discoveries could lead to estimated recoverable reserves of more than 100tcf by 2015. Production is expected to start in 2022.

Tanzania BG is a designated operator of offshore blocks 1, 3 and 4, with Ophir as its partner. Statoil Tanzania AS has discovered recoverable gas reserves in offshore block 2. Statoil is the designated operator of block 2, with ExxonMobil as its partner.

Despite the site being an important milestone towards realising an LNG development in Tanzania, observers warn that it is not a commitment to a final investment decision by the partners because it could be subject to further project definition and analysis.

Mr Mwapinga said a pending land dispute and security concerns due to the selected site being located in the open sea makes the Rushungi site, which has a natural harbour and is owned by the government, ideal for the project.

Mr Mwapinga said the selected area is owned by Mohammed Enterprises Tanzania Ltd (METL), one of the largest regional conglomerates. The company acquired the site, which was a sisal estate, in the 1960s, but never developed it. METL owns the land through Tasco Estate.

The land has seven different title deeds, and the company is said to have used them to borrow Tsh2.4 billion ($1.5 million) from a bank in Malaysia. The Ministry of Lands wrote a letter to the company notifying them of the government's intention to revoke the title deed.

"Over the years, villagers have intruded into the estate because it has been dormant. According to the land laws, the government can retract the title deed if the land hasn't been in use for three years, and it could also do so in the public interest," said Mr Mwapinga.

The site valuation report says despite the site requiring little or no dredging, the most technically viable location for the plant site will require the relocation of Rushungi village, and will occupy most of the productive land currently being used for agriculture.

"The site is relatively isolated and distant from the urban areas of Lindi town and Mtwara. Consequently, development of the site is unlikely to support regional level development. In addition, the likely influx of people and associated unplanned development would be difficult to manage and has the potential to disturb elephants that occasionally forage nearby," states the report.

The report further says that minimal physical resettlement and its marine conditions would provide for a safe and reliable LNG harbour, and its proximity to Lindi and Mtwara towns makes the Likong'o site preferable.

Minister for Energy and Minerals Sospeter Muhongo did not confirm whether Likong'o had been selected, but said a potential site had been chosen after the stakeholders conducted scientific research. He said the site was selected over 10 others, which were evaluated before a decision was made.

"The government would be liable if it made the mistake of choosing a site for the companies and anything went wrong," said Mr Muhongo.

Mr Muhongo said the project partners were still evaluating the amount of land that would be required, but the government wasn't compelled to rush the process because it wanted to make sure the country's interests were put first.


 
How much will it cost our GVT to buy back that LAND from METL ??? I'm SICK!!!
 
nngu007 said:
How much will it cost our GVT to buy back that LAND from METL ??? I'm SICK!!!
Click to expand...

Why buying? All land in the country is "owned" by the President; we are just using it at his pleasure. So, it is just the matter of changing the usage of the land in question but not buying it.
 
dudus said:
Why buying? All land in the country is "owned" by the President; we are just using it at his pleasure. So, it is just the matter of changing the usage of the land in question but not buying it.
Click to expand...

MO and his COMPANY ? they are CAPITALIST in nature; they know this will one day come back 2 their Advantages...
The SISAL ESTATE's were never developed by MO...

That LAND is preferred because it is closer to the OCEAN also there is minimal physical resettlement and its marine conditions for a safe and reliable LNG harbor...

Lakini wanasema kuna ELEPHANTS wanaozurura eneo hilo ni rahisi kuwahamisha...
 
dudus said:
Why buying? All land in the country is "owned" by the President; we are just using it at his pleasure. So, it is just the matter of changing the usage of the land in question but not buying it.
Click to expand...

Mh, owned by the president or public?

Sent from my BlackBerry 9700 using JamiiForums
 
nngu007 said:
How much will it cost our GVT to buy back that LAND from METL ??? I'm SICK!!!
Click to expand...

Lipa deni malaysia huko:

By the way 1960 METL au TASCO ilikuwepo?

Mr Mwapinga said the selected area is owned by Mohammed Enterprises Tanzania Ltd (METL), one of the largest regional conglomerates. The company acquired the site, which was a sisal estate, in the 1960s, but never developed it. METL owns the land through Tasco Estate.



The land has seven different title deeds, and the company is said to have used them to borrow Tsh2.4 billion ($1.5 million) from a bank in Malaysia. The Ministry of Lands wrote a letter to the company notifying them of the government’s intention to revoke the title deed



 
[h=3]Cost of LNG plants[edit][/h]For an extended period of time, design improvements in liquefaction plants and tankers had the effect of reducing costs.
In the 1980s, the cost of building an LNG liquefaction plant cost $350 per tpa (tonne per year). In 2000s, it was $200/tpa. In 2012, the costs can go as high as $1,000/tpa, partly due to the increase in the price of steel.[SUP][18][/SUP]
As recently as 2003, it was common to assume that this was a "learning curve" effect and would continue into the future. But this perception of steadily falling costs for LNG has been dashed in the last several years.[SUP][20][/SUP]
The construction cost of greenfield LNG projects started to skyrocket from 2004 afterward and has increased from about $400 per ton per year of capacity to $1,000 per ton per year of capacity in 2008.
The main reasons for skyrocketed costs in LNG industry can be described as follows:

  1. Low availability of EPC contractors as result of extraordinary high level of ongoing petroleum projects world wide.[SUP][9][/SUP]
  2. High raw material prices as result of surge in demand for raw materials.
  3. Lack of skilled and experienced workforce in LNG industry.[SUP][9][/SUP]
  4. Devaluation of US dollar.
The 2007–2008 global financial crisis caused a general decline in raw material and equipment prices, which somewhat lessened the construction cost of LNG plants. However, by 2012 this was more than offset by increasing demand for materials and labor for the LNG market.
 
WAJINGA NDIO WALIWAO, SISI TUSHAPIGWA 30 USD Billion.


Liquefaction Project at Cameron LNG
As a result of the improved outlook for domestic natural gas production, in 2011 Cameron LNG proposed adding natural gas liquefaction and export facilities to its existing terminal in Hackberry, Louisiana. The U.S. today has more than a 100-year supply of natural gas and exporting a small amount of liquefied natural gas (LNG) would create U.S. jobs, provide economic benefits to the nation and help reduce our trade deficit.

Cameron LNG obtained approval from the U.S. Department of Energy (DOE) to export up to 12 Mtpa, or approximately 1.7 Bcf per day, of domestically produced LNG to all current and future Free Trade Agreement countries and on February 11, 2014 received conditional authorization from the DOE to export LNG to non-Free Trade Agreement countries, including those in Europe and Asia. Cameron also has an application under review with the Federal Energy Regulatory Commission, the lead agency responsible permitting the new facilities.

The liquefaction project will use Cameron LNG's existing facilities, including two marine berths capable of accommodating Q-Flex sized LNG ships, three LNG storage tanks with a combined storage capacity of 480,000 cubic meters, and vaporization capability for regasification services of 1.5 billion cubic feet (Bcf) per day.

The completed liquefaction facility will be comprised of three liquefaction trains capable of exporting up to 12 million tonnes per annum (Mtpa), or approximately 1.7 billion cubic feet per day of liquefied natural gas . In addition, a new 21-mile natural gas pipeline, a compressor station and modifications to existing pipeline interconnections are proposed (read more here). Construction on the project is planned to start in 2014 with the first LNG production in 2017, and full commercial operation in 2019.

The new and existing facilities will be wholly owned by Cameron LNG Holdings, LLC, a joint-venture with 50.2 per cent indirectly owned by Sempra Energy (Sempra) and the remaining owned by GDF SUEZ S.A. (GDF SUEZ), Japan LNG Investment, LLC (a joint venture entity that has been formed by subsidiaries of Nippon Yusen Kabushiki Kaisha (NYK) and Mitsubishi Corporation (Mitsubishi)) and Mitsui & Co., Ltd. (Mitsui) each owning a further 16.6 per cent.

The total project cost is anticipated to be between $9 to $10 billion, the majority of which will be project-financed and the balance provided by the project partners. Cameron LNG expects to secure financing for the project during 2014.
 
Benefits
With an estimated capital cost of $6 to $7 billion, and an annual LNG exports averaging $8.6 billion, many benefits-both locally and regionally-will result from the construction and operation of the Cameron LNG liquefaction facilities, including:
Jobs: The design, engineering and construction of the project will result in the creation of an average of more than 1,300 on-site engineering and construction jobs over a four-year period. During the peak 12-month period, approximately 3,000 jobs will be directly created, as well as hundreds of additional off-site jobs to support the design, fabrication and construction of the facilities.
Economic: Cameron LNG estimates that the liquefaction project customers will export an average of approximately $8.6 billion of LNG per year, and oil and natural gas liquids production is expected to average $2.2 billion-averaging total trade balance benefits of $10.8 billion per year based on 2011 dollars.
 
liquefaction.jpg


Project schedule summary

[TD="bgcolor: transparent"]November 2011[/TD]
[TD="bgcolor: transparent"]Commencement of Front End Engineering Design[/TD]

[TD="bgcolor: transparent"]January 2012[/TD]
[TD="bgcolor: transparent"]Cameron LNG received approval from the Department of Energy (DOE) to export up to 12 MTPA of domestically produced LNG from the Cameron LNG terminal to all current and future Free Trade Agreement countries.[/TD]

[TD="bgcolor: transparent"]April 2012[/TD]
[TD="bgcolor: transparent"]Submit request to FERC to initiate pre-filing review process[/TD]

[TD="bgcolor: transparent"]December 2012[/TD]
[TD="bgcolor: transparent"]Filing of NGA Section 3 application to FERC[/TD]

[TD="bgcolor: transparent"]2013[/TD]
[TD="bgcolor: transparent"]Signed joint-venture and tolling agreements[/TD]

[TD="bgcolor: transparent"]January 2014[/TD]
[TD="bgcolor: transparent"]Draft Environmental Impact Statement (DEIS) issued by FERC[/TD]

[TD="bgcolor: transparent"]February 2014[/TD]
[TD="bgcolor: transparent"]Received conditional DOE Non-Free Trade Agreement license[/TD]

[TD="bgcolor: transparent"]2nd Quarter 2014[/TD]
[TD="bgcolor: transparent"]Expect to receive Final Environmental Impact Statement from FERC[/TD]

[TD="bgcolor: transparent"]2014[/TD]
[TD="bgcolor: transparent"]Construction begins[/TD]

[TD="bgcolor: transparent"]2017[/TD]
[TD="bgcolor: transparent"]Expect first production of LNG[/TD]

[TD="bgcolor: transparent"]2018[/TD]
[TD="bgcolor: transparent"]Expect all three trains to achieve commercial operation[/TD]
 
WAKATI THE BIGGEST IN WORLD INAJENGWA KWA 40 USD Billion sisi ya kwetu ya hapo Lindi inajengwa kwa 30 usd Bill

MACCM watatumaliza jamani.


The biggest building on Earth is Boeing's wide-body assembly plant in Everett, Wash. It covers an area as large as 18 Manhattan city blocks, stands 11 stories tall, and encloses almost 500 million cubic feet of space.
Imagine you have six of those buildings, all filled with natural gas from Alaska's North Slope. Your assignment: Figure out how to shrink the gas enough so that all of the methane in those six buildings can be loaded onto a single, 900-foot-long tanker and shipped to market.
The solution: Supercool the gas to 260 degrees below zero, so that it turns into a liquid.
Now the molecules will be packed so tight that the gas - which once reached all the way to the 114-foot ceiling - will be a puddle just over two inches deep on the floor. At that shrunken volume, liquefied natural gas can be loaded aboard insulated tankers - sort of like floating Thermos bottles - for shipment around the world.
That process is at the heart of the latest proposal for getting the North Slope's vast natural gas reserves into the hands of buyers.


But transformation comes at a high price. A liquefied natural gas plant able to operate on the scale sketched above, which is now being considered for Alaska by ExxonMobil, BP and ConocoPhillips, could cost $20 billion or more to construct, based on the price tag of similar projects around the world in recent years.
And that's only one item on the invoice. Throw in a short pipeline to bring gas from a newly developed North Slope field to Prudhoe Bay, plus what would be one of the world's largest gas treatment plants at Prudhoe to purify the methane stream, plus an 800-mile pipeline to get the gas from the North Slope to the LNG plant at tidewater in Southcentral Alaska, plus up to eight compressor stations along the way to keep the gas moving.
Then add in massive storage tanks at tidewater to hold the LNG while waiting for four or five tankers to arrive each week, the docking jetty, berths and loading equipment, and you begin to see the reality behind the producers' estimate of $45 billion to $65 billion for the total cost of the project they call Alaska South Central LNG.
[h=3]LIQUEFACTION PLANT COSTS[/h]The producers haven't broken out details of their cost estimates, such as specifics for the tidewater LNG plant. But it's possible to sift the $20 billion ballpark estimate from public data assembled by international energy consulting firm Wood Mackenzie, and by oil and gas producer Apache Corp., which itself wants to build an LNG export operation with partner Chevron at Kitimat, B.C.
Wood Mackenzie examined the subject in a 2011 report for the Alaska Gasline Port Authority, vocal proponents of an LNG terminal at Valdez. Wood Mackenzie estimated building an Alaska LNG plant would cost $1.2 billion per million metric tons of capacity. (Liquefied natural gas generally is measured in tons, as opposed to its vaporous cousin, which is measured in the cubic feet of space it fills up. A ton of plant capacity is the ability to produce one ton of liquefied gas per year.)
Apache, meantime, early this year assembled capital costs for 10 foreign LNG plants that started construction in the past three years; the average came to around $1.26 billion per million tons of annual capacity.
The Alaska project, as proposed by the three producers and TransCanada, their pipeline-building partner, would have an output capacity of 15 million to 18 million tons a year. Assume an Alaska project costs the same to build as those in Papua New Guinea, Australia, Angola, Indonesia and other places considered in the two studies cited above, and you get a cost range of $18 billion to $23 billion.
Of course, if you allow for higher construction costs in Alaska and inflation - the Wood Mackenzie estimate was in 2011 dollars and Apache's summary includes projects started since 2010 - the Alaska LNG plant could cost more than $20 billion.
However, James Jensen, a Massachusetts-based consultant in natural gas economics, notes that the Apache figures rely to a considerable extent on a special case: Australia, home to seven of the 10 plants in the Apache roundup. "The Australians," Jensen said, "have basically lost control of their costs. They're going crazy."
One example: An Australian project called Gorgon LNG. It was originally projected to cost $37 billion; the latest estimate is $52 billion, though the foreign exchange rate for Australian dollars is part of the cause.


The Australian example, Jensen believes, may be prompting project sponsors elsewhere to allow plenty of wiggle room in their own estimates.
"I'm sure everybody in Alaska is putting in a lot of contingency to avoid getting clobbered like with the Australian projects," he said.
What accounts for the soaring costs of Gorgon and the other Australian projects? Essentially, it's critical shortages of labor and expertise. Experts watching the Australian situation, Jensen said, attribute it to "too many projects moving too fast based on too small a workforce and too few contractors in too small a country."
He cites the contractor crunch in particular. "There is a limited number of companies who can do these projects on time and on budget, and these guys don't even answer their telephones anymore."
Still, even Jensen doesn't think an Alaska project could come cheap. His own computer model for a "standard" LNG plant puts the cost of the producers' South Central LNG plant with a capacity of 18 million metric tons - including an allowance for the higher cost of doing business here - at a little over $14 billion.
Meanwhile, Resources Energy Inc., a group of Japanese companies looking to get into the game on the Alaska liquefaction plant project, in May unveiled its own estimate of $23.7 billion for an LNG plant at Valdez capable of 20 million tons a year, or almost $1,200 per ton.
Whatever the best guess, why so much? What makes the massive supercooling plants so expensive?
[h=3]ECONOMIES OF SCALE[/h]When it comes to LNG plants, the decision usually boils down to two choices: big, or even bigger.
That's because the bigger the plant, the lower the cost of each ton of LNG it can produce.
"It's not as if you can build a 4 million-tons-per-year plant and it'll be half the cost of an 8 million-tons-per-year plant," said Nelly Mikhaiel, a gas and LNG consultant with FACTS Global Energy. "It doesn't work that way. You try to make it as big as possible to achieve economies of scale."
Mikhaiel ticked off a list of what has to go into an LNG export project, depending on location: liquefaction trains; storage tanks; docks and jetties for loading the LNG onto tankers; utilities such as power, water and sewer; control rooms; shops; warehouses; perhaps even permanent housing for staff.
"It's hard to wrap your head around just how big they are," Mikhaiel said.
Source: Chevron​
The first phase of the workforce accommodations are complete at Chevron's Wheatstone LNG project in Western Australia. When completed, the construction community will house 5,000 workers. (Click to enlarge.)

Indeed, she noted, building what's needed just to get started on an LNG plant can be a substantial construction project in itself: roads, airstrips, construction docks for material and equipment delivery, utilities, and housing for construction workers.
The need to build a small town before construction can even commence, she said, "is an indicator of the size, complexity and, therefore, cost of the undertaking."
The three-train South Central liquefaction facility will be big a pretty big and complicated one if it's ever built. The project sponsors estimate it could cover up to 600 acres, equal to over 100 Manhattan city blocks. It would be almost a city unto itself, complete with its own utilities and, at its peak, a workforce that could reach 5,000 people.
(An LNG train, or module, is one complete stand-alone processing unit, capable of carrying out all of the steps in the complex process of turning natural gas, from its vapor form, into liquid methane. Thus, an LNG plant with two trains can produce twice as much as a single-train plant, and so on.)
Other, more transient cost factors are also at play today, Mikhaiel said. Like Jensen, she pointed to the demand for contractors and workers with expertise in LNG plants. In addition, she noted that these same workers and contractors are in demand by other booming industries that need similar expertise, such as oil, petrochemicals and mining. Consequently, contractors and laborers alike can charge premium rates.
Moreover, she said, prices for the raw materials needed for an LNG plant - steel, for example - have been on the upswing recently, further increasing costs.
In Alaska's case, location is an additional cost factor. Doing anything costs more where the weather is harsh, and workers have to be paid more to entice them to do the work in such weather in remote locations.
"It really is a perfect storm in many respects when looking at the capital expenditure costs for LNG projects," Mikhaiel said.
[h=3]OTHER PIECES OF THE PIE[/h]While the LNG facility at tidewater may wind up as the most expensive component of the Alaska project, there are also other costly construction tasks, each possibly approaching a billion dollars - or multiples thereof.
There is the short pipeline from the Point Thomson field (with 8 trillion feet of gas, almost one-quarter of the North Slope's proved reserves), the gas treatment plant at Prudhoe, the pipeline to Southcentral Alaska and its compressor stations, and LNG storage tanks at the end of the pipe.
The Office of the Federal Coordinator prepared the following ranges - using cost estimates from previous efforts by TransCanada and by the producers to develop North Slope gas - merely as examples to show what such components can cost.
Source: SCLNG​
A coastal Alaska LNG-export plant could look something like this illustration, provided by the South Central LNG project sponsors. (Click to enlarge.)

Differences between projects, such as the size of the pipe, steel specifications, capacity of the gas treatment plant, construction plans and other variables all mean these numbers are, at best, within a ballpark range - think large outfield, not the tighter confines of the infield - for the South Central Alaska LNG project. For example, the output of the South Central LNG plant would be less than either of the two proposed producer-led projects in recent years, no doubt affecting the numbers.
Put the numbers for all the components into the Osterizer, add some more numbers for the LNG loading facilities, tanker berths, utilities, support buildings and other pieces of the project, hit the mix button and you get a rough estimate of the cost range for a South Central-scale project in $40s billion to $50s billion range - pretty close to the numbers released by the South Central project sponsors.
[h=4]Point Thomson pipeline[/h]The 58-mile line would carry natural gas to Prudhoe from Point Thomson, a long-known North Slope natural gas and condensate field under construction and scheduled to start liquids production in the winter of 2015–2016 - with gas production to follow just as soon as there is a pipeline to market. ExxonMobil is the field operator. The gas line would be included in the South Central LNG development; it is not part of Exxon's Point Thomson project, which includes its own, separate oil line.
The short gas line was estimated in recent years to cost as much as $800 million.
That comes from two earlier proposed North Slope natural gas projects that submitted filings with the Federal Energy Regulatory Commission in recent years - the BP/ConocoPhillips project known as Denali, which closed down in 2011, and the ExxonMobil/TransCanada proposal known as the Alaska Pipeline Project.
Under the earlier ExxonMobil-TransCanada proposal, presented in 2010, the Point Thomson line would be sized to move 1.1 billion cubic feet of gas a day westward to the operations at Prudhoe Bay. That project proposed feeding as much as 5.3 billion cubic feet of gas a day from Prudhoe Bay and Point Thomson into the gas treatment plant, sending 4.5 bcf a day of cleaned gas down the line to Alberta to connect with North American markets.
The current venture of TransCanada and the producers told the Alaska Legislature in February it anticipated the mainline moving 3 bcf to 3.5 bcf per day from the North Slope. After subtracting the gas consumed along the way at pipeline compressor stations, gas withdrawn along the way for Alaska's needs, and gas burned up at the liquefaction plant to power the process, the companies figure they would have 2 bcf to 2.4 bcf a day of natural gas ready to ship out as LNG.
The venture also told lawmakers in February that 2 bcf to 2.5 bcf of gas a day would come from Prudhoe Bay, and 1 bcf a day from Point Thomson, depending on seasonal fluctuations. Under the current producer-TransCanada venture, the Point Thomson line would be 30 inches in diameter.
[h=4]Gas treatment plant[/h]Just a few years ago, this was estimated at $9 billion to $13 billion, though for a larger project at the high end of that range. This massive North Slope facility would purify, chill and compress gas from Point Thomson, Prudhoe and possibly other fields to prepare it for shipment to market. It's worth noting that any project to move gas off the Slope would require a facility to remove impurities, especially carbon dioxide.
Source: SCLNG​
The South Central LNG project team provided this illustration of a possible layout for the North Slope gas treatment plant. (Click to enlarge.)

Treatment is required because North Slope gas in its natural state, like most gas deposits, is unsuited for market or transmission by pipeline. Cleaning out corrosives such as hydrogen sulfide from the gas stream before sending the gas to the mainline is essential.
The Prudhoe Bay gas stream coming into the plant would run about 12 percent CO[SUB]2[/SUB], which would be removed and pumped back down into the reservoir to help pressurize North Slope fields and aid in oil recovery. The Point Thomson gas flow is about 4 percent CO[SUB]2[/SUB].
The four-train plant would be among the largest in the world, according to the South Central LNG team. Its footprint could measure as much as 250 acres (about 50 Manhattan city blocks) and it would require up to 300,000 tons of steel for construction. That's as much steel as four, maybe five of the largest nuclear-powered aircraft carriers in the U.S. fleet.
While that's about as much as been revealed on the gas treatment plant for the current proposal, Denali's preliminary design for its four-train treatment plant went into more detail, envisioning 95 modules totaling 270,000 tons in weight. These included 18 CO[SUB]2[/SUB]-removal modules, eight compression modules, three chilling modules, a power plant, utilities and other buildings. Moving all that equipment to the North Slope would require logistical skills - and spending - reminiscent of the trans-Alaska oil pipeline construction almost 40 years ago.
The gas treatment plant cost numbers used in this report come from filings with FERC by Denali and the earlier ExxonMobil/TransCanada projects, which were both larger in capacity than the plant proposed for the current LNG project.
[h=4]Pipeline to Prince William Sound or Cook Inlet[/h]The South Central LNG team says the line would be 42 inches in diameter and, like the trans-Alaska oil pipeline, about 800 miles long. The pipe would be buried along most of the route, with trenching and pipe-laying work limited to winter when the frozen ground can support heavy equipment.
For much of the route, depending whether it ends at Prince William Sound or Cook Inlet, the gas pipeline would roughly parallel the oil line. The project team's last public statement on the liquefaction terminal site was that they had narrowed the list to four possible sites; no locations were provided.
The pipeline would be designed to move as much as 3.5 bcf of gas a day, making it the largest gas pipeline in North America. The line would require up to 1.2 million tons of steel. The gas would be pressurized for the ride to tidewater at more than 2,000 pounds per square inch, requiring thick-wall pipe.
The earlier TransCanada/Exxon proposal for a similar pipeline to Valdez estimated the cost at $11 billion to $14 billion.
[h=4]LNG storage tanks[/h]
Source: Chevron​
Each storage tank under construction at the Gorgon LNG project in Australia will be able to hold a tanker load of supercooled gas, waiting for shipment to overseas customers. (Click to enlarge.)

The project team says two storage tanks would be built at the liquefaction terminal, each capable of holding about 3.5 billion cubic feet of gas in the form of LNG, maybe a day and a half's production from the liquefaction plant and enough to fill a good-sized tanker.
The companies have not provided any costs estimates for the tanks - and no LNG tanks were proposed for the earlier Denali or TransCanada/ExxonMobil projects to move gas to North America by pipeline - but recent LNG storage projects in Singapore and Greece provide a range for possible costs.
A Greek company last year advertised for bids for construction of an LNG storage tank about one-third smaller than the tanks proposed by South Central LNG, with the cost estimated at $150 million.
Singapore LNG Corp. is considering a huge storage tank for its receiving terminal, more than 50 percent larger than the tank proposed for the Alaska project. The company estimates the tank could cost around $500 million.
[h=3]ALASKA LNG NOT ALONE IN HIGH COSTS[/h]When it comes to Alaska natural gas project ideas, today's South Central proposal is the latest in a series running back 40 years. The first was floated before construction of the oil pipeline, in the dawn of Alaska's North Slope oil boom.
The Arctic Gas project, as it was called, envisioned a 4,512-mile gas pipeline system running east from Prudhoe Bay to Canada's Mackenzie River delta and then south to markets in Canada and the United States. As of 1975, it was estimated to cost "only" $6.7 billion. Still, that's equivalent to about $29 billion in today's dollars, the first sign that no North Slope gas project was ever going to be cheap.
Fast-forward to the South Central project. ExxonMobil, BP and ConocoPhillips hold rights to most of the known natural gas resources on the North Slope, while TransCanada is the largest natural gas pipeline operator in North America.
What about that gigantic price tag of $45 billion to $65 billion? At the top end, it's more than five times Alaska's current annual state budget. At that price, does it leave Alaska with a realistic shot at the world market?
As it happens, numbers in that ballpark come up with some regularity around the globe.
Source: Chevron​
The export jetty and berths for the Papua New Guinea LNG project, outside Port Moresby. The plant is expected to ship its first gas in 2014. (Click to enlarge.)

Last year, a CNN Money survey of the 10 most expensive energy projects in the world included five liquefied natural gas projects expected to cost more than $30 billion each.
Topping the list of such projects was Gorgon with its $52 billion price tag. Located off Australia's coast, it's under development by Chevron, ExxonMobil, Royal Dutch Shell and a couple of Japanese utilities. It's similar in output capacity to the Alaska project, maybe a bit smaller. One substantial difference is that gas field development costs are included in Gorgon's $52 billion price tag. Construction is under way, with first gas expected in 2015.
Because of their huge size, LNG projects - those of Alaska and its competitors alike - will require, first, huge markets to absorb their output, and, second, a solid likelihood that gas prices in those markets will remain high enough over the life of the project to make it profitable, ideally in the form of long-term contracts.
A Deutsche Bank Markets Research report last year forecast it would take 13 years of operation before Gorgon LNG turns positive cash flow. It referred to an earlier Australia LNG project, North West Shelf, that the bank said took 20 years to get to positive cash flow for its developers.
[h=3]CAN ALASKA GAS COMPETE?[/h]Growing LNG demand in Asia is the opportunity that attracts gas producers to invest in megaprojects. Certainly, the cost of construction is an issue in an increasingly competitive marketplace. But the real price that matters is the cost of LNG landed at the dock in Japan, South Korea, China and elsewhere in Asia. That's the sum of producing the gas, moving it to a liquefaction plant, turning it into LNG and delivering it by tanker.
Some analysts think Alaska may have something of an edge over its rivals because it is closer - meaning shorter tanker runs and fewer tankers needed - to Japan and some of the other Asian markets. The U.S. Gulf Coast, East Africa and Qatar are much farther away than Alaska.
In addition, Alaska's North Slope gas production costs likely would be lower than undeveloped fields in the remote regions of British Columbia, coal-seam plays in Australia and isolated fields in Russia's Arctic. This is because much of the Alaska infrastructure - including wells - needed to produce gas has already been put in place for development of the North Slope oil fields.
Also worth noting is that Alaska gas largely escapes two issues complicating the issue of LNG exports from the Lower 48.
One is the process of hydraulic fracturing for getting gas out of shale rock. Fracking has raised concerns about possible contamination of drinking water supplies in the Lower 48. A reduction in fracking activity would likely mean a reduction in Lower 48 gas production, which could reduce the amount of gas available for export as LNG.
While fracking has gone on for years on Alaska's North Slope and may increase in the future, few people live in the area compared to shale gas plays in Pennsylvania and elsewhere in the Lower 48 states. In addition, the state is developing regulations that attempt to allay many of the concerns raised by fracking in the Lower 48. To date, hydraulic fracturing has not become controversial in Alaska.
The other Lower 48 issue is the concern that exporting LNG will reduce domestic supplies and raise natural gas prices for consumers there. But Alaska's North Slope gas is so far from Lower 48 markets that nearly four decades of effort have not found a way to get it there at a competitive price. Thus, sending it to Asia instead is unlikely to affect supplies or costs in other states.
The competiveness of North Slope gas in Asia comes down to price. It's not the only factor, but it's a big one. A senior gas analyst at the International Energy Agency told a Canadian newspaper this spring, speaking of the rush of proposed LNG exports worldwide: "Certainly the companies involved will be keen to see their projects moving forward but not under any condition. These projects must be competitive and make sense from an economic point of view."
 
Last year, a CNN Money survey of the 10 most expensive energy projects in the world included five liquefied natural gas projects expected to cost more than $30 billion each.
Topping the list of such projects was Gorgon with its $52 billion price tag. Located off Australia's coast, it's under development by Chevron, ExxonMobil, Royal Dutch Shell and a couple of Japanese utilities. It's similar in output capacity to the Alaska project, maybe a bit smaller. One substantial difference is that gas field development costs are included in Gorgon's $52 billion price tag. Construction is under way, with first gas expected in 2015.
Because of their huge size, LNG projects - those of Alaska and its competitors alike - will require, first, huge markets to absorb their output, and, second, a solid likelihood that gas prices in those markets will remain high enough over the life of the project to make it profitable, ideally in the form of long-term contracts.
A Deutsche Bank Markets Research report last year forecast it would take 13 years of operation before Gorgon LNG turns positive cash flow. It referred to an earlier Australia LNG project, North West Shelf, that the bank said took 20 years to get to positive cash flow for its developers.
 
Apache Corp. earlier this year assembled a chart of capital costs for LNG export plants going back to the 1970s, showing the dramatic increase in construction costs in recent years. The Apache official who presented the chart at an industry conference said the challenge is to control costs in LNG project development. (Costs are listed as per ton of annual LNG output capacity.) (Click to enlarge.)

LNG-2013-McArdle-13.png
 
Major components of
a large-volume Alaska LNG project
Point Thomson gas pipeline

  • 58-mile, 30-inch-diameter pipeline to move natural gas from the Point Thomson field to Prudhoe Bay.
  • Estimated at as much as $800 million by North Slope producers in 2010.
North Slope gas treatment plant

  • Among the largest in the world, the plant would remove carbon dioxide and other impurities from the gas stream.
  • A larger version of the plant was estimated at $9 billion to $13 billion by North Slope producers in 2010.
North Slope pipeline to tidewater

  • 800 miles of 42-inch-diameter pipeline from Prudhoe Bay to a liquefaction plant site on Prince William Sound or Cook Inlet.
  • A slightly larger pipeline was estimated at $11 billion to $14 billion by TransCanada/ExxonMobil in 2010.
Natural gas liquefaction plant

  • One of the world's largest liquefaction plants to produce LNG.
  • Capacity to produce as much as 900 billion cubic feet of gas a year as LNG (averaging 2.4 bcf a day).
  • Possibly $18 billion to $23 billion, based on construction costs of LNG plants worldwide the past three years.
LNG storage tanks

  • Two storage tanks, each capable of holding enough LNG to fill a standard-size tanker.
  • A smaller-size tank in Greece was estimated at $150 million last year, and a larger version in Singapore was estimated at $500 million.
 
US energy major Chevron has raised the cost estimate for its huge Gorgon liquefied natural gas plant in Western Australia by a further $US2 billion ($2.2 billion), but worries remain in the market that a further increase beyond the revised $US54 billion is still possible.
The latest overrun makes the latest budget 46 per cent higher than the original for the project, Australia's largest single resources investment, which will also see a further delay in the production start-up to mid-2015.
The economics of Gorgon were still ''attractive'', vice-chairman George Kirkland said.
Last December, the group raised the cost estimate from $US37 billion to $US52 billion. The original start-up date was late next year, before being moved back to the first quarter of 2015 a year ago.
Construction of Gorgon, involving 15.6 million tonnes a year of LNG capacity in three trains, has been dogged by productivity and weather issues.
The problems have affected the arrival of critical equipment on the quarantine nature reserve of Barrow Island off the WA coast, and work on the island, where Chevron is operating under severe environmental and space constraints.
The project, in which ExxonMobil and Shell both have 25 per cent stakes, is almost 75 per cent complete. Exxon and Shell are believed to be assuming a final cost for Gorgon close to $US60 billion.


Read more: Another $2b cost blowout for Gorgon LNG
 
Acheni tabia ya kufuta post za watu! Ninauliza tena:

1)METL walinunua hayo mashamba mwaka gani?
2)Na shilingi ngapi?
 
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