Capacity and Technology for the Snohvit LNG Plant
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Transcript of Capacity and Technology for the Snohvit LNG Plant
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CAPACITY AND TECHNOLOGY FOR THE SNHVIT LNG PLANT
CAPACIT ET TECHNOLOGIE DES INSTALLATIONSGNL DE SNHVIT
R.S. HeierstedR. E. Jensen
R. H. PettersenS. Lillesund
Den norske stats oljeselskap a.s. (Statoil)Stavanger, Norway
ABSTRACT
The Statoil paper will give an insight into the selection of capacity and technology for
the Snhvit LNG Plant development. The initial plant design was a single train of 3.4million tonnes of LNG per annum capacity. Recent screening studies indicate that LNG
train capacity contributes significantly to the economy of scale. A decision on the Snhvit
single train capacity will be balanced against specific risks related to the involved
technology. The verification will particularly focus on technology exceeding present
industrial practice when increasing train capacity into the range of 4.0 - 5.0 mtpa of LNG
production.
RESUME
Lintervention de Statoil donnera un aperu de la slection effectue, quant la
capacit et la technologie, pour le dveloppement des installations GNL de Snhvit.Initiellement, ces installations sont un train simple dune capacit de 3,4 millions de
tonnes de GNL par an. Les tudes de dtail rcentes indiquent que la capacit du train de
GNL a une incidence significative sur lconomie dchelle. Une dcision portant sur la
capacit du train simple de Snhvit sera galement value en regard des risques
spcifiques relatifs la technologie utilise. La vrification se penchera tout
particulirement sur la technologie dpassant la pratique industrielle actuelle, puisque la
capacit du train devrait tre augmente pour passer une production de GNL de lordre
de 4,0 5,0 mt/an.
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CAPACITY AND TECHNOLOGY FOR THE SNHVIT LNG PLANT
1 THE SNHVIT LNG CHAIN
The gas reserves in the Barents Sea off the coast of Northern Norway were discovered
in the early 1980s, and are located in three different fields, Askeladd, Albatross andSnhvit. The development of all three fields will be part of the Snhvit project. The fields
are operated by Statoil. Other field owners are Norsk Hydro, TotalFinaElf, RWE-DEA,
Amerada Hess and Svenska Petroleum.
The Snhvit project aims at cost efficiency in all aspects of the development, being in
the fore front of technology and execution methods to obtain the lowest unit production
costs. Regarding the chain capacity, the project has balanced risks related to the reserves,
the offshore and onshore technology and market potential. The reserves will be
commercialised through a grass root LNG chain of 4.3 million tonnes per annum
capacity.
The gas fields are located 160 kilometres offshore in 300 to 350 metres water depth.
The total reserves are in excess of 300 billion standard cubic metres of gas and 20 million
cubic metres of condensate. The field development will comprise a subsea production
system and the well stream will be transported to the onshore receiving facilities in a
multiphase transportation pipeline. The offshore system and multiphase pipeline is
designed to obtain reliable operations under the given conditions.
The LNG plant will be situated on the Melkya Island in the vicinity of the city of
Hammerfest. The plant development meets constraints, particularly on personnel air
transport logistics and the fact that Norwegian labour regulations restrict personnel
rotation options, all of which will have an impact on the investment costs. The LNG plantconstruction strategy is based on maximum prefabrication. The basic concept is to install
a base load LNG process train and most of its utilities on a purpose built barge and ship it
to site. Compared to other LNG plant executions, the Snhvit project has changed the
philosophy from on-site, stick-built solutions to yard prefabrication, placing focus on
maximum work executed in fabrication yards.
Acquiring shipping capacity has been a focus area. Given the planned LNG
production capacity and the sales portfolio, the Snhvit project will need four LNG
carriers with a capacity of 145.000 m3
each. The shipping distances from the Snhvit area
to alternative markets balances with the current sales portfolio comprising southern ports
of Continental Europe and terminals in USA. The Snhvit project is aiming at increasedcommercial robustness by selling its production capacity to markets with different pricing
mechanisms.
2 THE ENVIRONMENTAL EDGE OF SNHVIT
The design of the overall thermal efficiency of the LNG plant must meet economic
criteria and environmental constraints. The life cycle cost robustness of the technology
versus future purchase of quota according to the Kyoto Protocol and criteria related to
Best Available Technology is relevant in a Norwegian context. The cogeneration of
power and heat production must meet stringent requirements on CO2 and NOx emissions.
Therefore, the selection of energy optimised processes for the gas sweetening and gasliquefaction is important.
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As a significant measure in the environmental strategy of the project, the carbon
dioxide will beseparated from the well stream gas at the onshore pretreatment facilities
and pumped for transport and deposition in an offshore structure. This concept resembles
the underground storage of carbon dioxide alreadyproven feasible by the Sleipner Field
in the NorthSea.
3 SCREENING PROCESS TECHNOLOGY FOR TRAIN SIZING
In order to improve the economy of scale, by reducing unit cost of produced LNG and
thus increase the net present value, the project performed a screening study on increasing
the capacity of the LNG plant, involving the main engineering contractors, the technology
licensors and the machinery vendors.
The objectives of the screening were to select the optimum capacity increase and
recommend the optimum technical solutions for the capacity increase based on high
thermal efficiency, maximum economy of scale effect and lowest life cycle cost. This also
included identification of the main technology qualification work for the recommendedsolution in order to reduce the risk with respect to increased capacity.
The study was based on the initial concept of train capacity of 3.4 million tonnes
LNG per annum. The contractors identified several potential schemes up to 150 %
capacity. The short listed schemes were evaluated in more details taking into
considerations given evaluation criteria such as life cycle cost, equipment size and
duplication, availability, impact on barge size etc. These evaluations resulted in some
recommended cases. Special consideration was given to equipment sizing for the carbon
dioxide removal and liquefaction process design.
The screening comprised several different driver options including industrial heavy
duty gas turbines and aeroderivative machines. Both mechanical drive of refrigerant
compressors as well as electrical motors as compressor drivers were considered. Both
steam and hot oil were evaluated as waste heat recovery system.
Relative investment (investment cost related to 100 % capacity) versus capacity,
revealed a significant economy of scale effect by increasing the capacity up to 150 %. The
scale up factor corresponded to an exponent of approximately 0.6 - 0.7. The best
potential of combining reduced unit cost with moderate technology and plant complexity
is a single LNG train capacity around 135 - 145 %. If capacity increases beyond 150 %
this might trigger two LNG trains. Taking all relevant risks into consideration, the
Snhvit project decided an LNG production capacity in the single train of 4.3 mtpa.
Subsequently after having set the capacity based on screening results, the project
initiated a feasibility study. The scope focused on process selection with high thermal
efficiency. The contractors were specifically asked to develop two driver configurations,
one based on steam and one based on hot oil as waste heat recovery system.
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4 SCREENING DRIVER/COMPRESSOR CONFIGURATIONS
Statoil provided a list of pre-qualified drivers subject to the screening study. A
prerequisite is all gas turbines to be equipped with low-NOx (DLE/DLN) combustors. The
GE LM6000PD was not pre-qualified to be used in mechanical drive service on the basis
of the present record of operation.
The screening resulted in several alternative driver and compressor configurations,
comprising both direct mechanical and indirect compressor drive by means of Gas
Turbogenerators and electric VSD (Variable Speed Drive) motors.
Combinations of gas turbines, helper motors, generators, steam turbines and electric
VSD motors were selected to satisfy the power demands of the compressor drivers,
process heat and electric power requirements of the LNG plant.
To reach the most robust driver configuration design, the project is applying life cycle
cost evaluations, taking the Norwegian offshore CO2 tax regime and BAT (Best Available
Technology) recommendations into the screening/selection criteria. Driver designs arechecked versus fuel gas prices, reflecting upstream investments and carbon dioxide taxes
of respectively 125 - 300 NOK per tonne.
Under this regime, only the most energy efficient designs will be competitive. Plant
availability is another selection criteria, especially with regards to increased on-stream
days versus investments.
5 AVAILABLE TECHNOLOGYLICENSED LNG PROCESSES
In 1997 the Snhvit project requested three contractors ( Kellogg, Bechtel and Linde )
to carry out conceptual designs for a baseload LNG plant located at Melkya in NorthernNorway.
Kellogg selected the APCI propane pre-cooled process, C3/MCR Liquefaction
Process, in their design. This is the far most utilised process for base load LNG plants,
and have been utilised in virtually all base load LNG plants installed the last 20 years,
with some few exceptions.
Bechtel applied the Optimised Cascade Liquefaction Process based on Phillips
technology.
Linde based their design on a dual flow liquefaction process but proposed to change
their design in eventual further stages of the project to a newly developed, proprietaryMixed Fluid Cascade Process, the MFC process.
After evaluations of these three conceptual designs, the project decided to award an
Extended Conceptual Engineering contract to Kellogg and Linde. The Bechel proposed
technology was rejected for further studies, since it turned out that its overall energy
efficiency was too low compared to the MFC process and the C3/MCR process, which
virtually have the same efficiency.
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6 TECHNOLOGY QUALIFICATION
The technology offered in the Extended Concept Engineering was qualified in
accordance with Statoil Quality Control System. This technology qualification was based
on a yearly LNG production capacity of 3.4 mtpa. The train capacity increase to 4.3 mtpa
made it necessary to perform a new and more extensive technology qualification.
The main purpose of technology evaluation is to get a firm basis for decision, where
minimising risk is the main issue. A precondition for the use of any risk assessment
techniques is that acceptance criteria is outlined. This naturally will shape the format of
the evaluation, direct the focus to areas of importance and determine whether a risk is
acceptable or not.
Today no exact and broadly agreed set of criteria is available in the industry. For the
purpose of this work the following acceptance criteria have been jointly drawn up by the
licence partners in Snhvit.
These overall guidelines were used, when performing the evaluation of the technologiesinvolved:
When departing from known established technology, the stipulation of the acceptance
criteria shall be based on the established technology, such as established, recognised
standard. The new technology may be accepted, if the analysis demonstrate that specified
characteristics such as risk contribution and unreliability do not increase in relation to the
reference solution, the established and recognised standard.
For rotating machinery, technical solutions are regarded as prototypes as long as
machines in similar service have not successfully accumulated at least 10 000 hours on
one machine and additional, the total fleet has accumulated 100 000 hours.
If the above criteria are not fulfilled, and the proposed technical solution deviates
from established technology, the gap shall be analysed. Quantities such as safety factors,
experience in form of running time at similar service, testing and verification program etc.
shall be used in the analysis. Together with any compensatory measures required, this
shall form the basis for proofing that the risk level will be in line with the risk level for
proven technology.
6.1 APCI liquefaction technology
APCI has delivered technology to the majority of LNG base load plants. Virtually all
of these plants have been based on their C3/MCR technology. However, for the increased
single train capacity of the Snhvit project, the Dual Mixed Refrigerant process was
considered.
The technology evaluation showed that either processes could be used, and that there
are no identifiable advantages of DMR over C3/MCR for this specific case. APCI
recommended to select the well proven C3/MCR technology.
No technology stoppers were identified when assessing the technology selection.
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6.2 Linde liquefaction technology
The MCP process proposed by Linde is in principle a cascade process, with the
important difference that pure refrigerant cycles are replaced with mixed refrigerant
cycles, and thereby improving efficiency and operational flexibility.
Comparison work were performed between single flow, dual flow and mixed fluid cascade
process options. Linde concluded that the MFC process was the most advantageous process.
The following characteristics were found to apply to the MFC process:
The process is new, and as a whole without any industrial references. However,
theconcept is build up by well known elements.
The liquefaction process utilizes a plate fin heat exchanger for pre-cooling, and two
separate SWHE for liquefaction and sub-cooling.
The size and complexity of the SWHE applied in the MFC process is considerably less
when compared with todays dual flow LNG plants.
The technology qualification has not revealed any technology stoppers in selection the
Linde MFC process. The integrity and operability of the Linde SWHE has been proven by
a test plant in Mossel Bay, South Africa. All critical elements of the liquefaction process
have either references to plants in similar service, or have been qualified by extensive
testing and verification calculations, based on sound engineering practice.
7 LARGE LNG STORAGE CONCEPT
The potential advantages of adopting one 220,000 m3
LNG tank over the two times
110,000 m3 option became apparent when judged on an economic and project executionbasis. These advantages included reduced labour and equipment requirements leading to a
reduced effect on the local community and environment.
In order to assess the viability of a 220,000 m3
LNG storage tank, studies have been
carried out based on a 9 % nickel inner tank and a pre-stressed concrete outer tank. Inner
tank designs have been completed for both full height and partial hydro-test to identify the
impact on shell thickness. Such large tank designs can be based on the rules of API 620
which requires a partial height hydrostatic test. If the tank were to be subjected to a full
height hydrostatic test, then the design of the inner tank would exceed the API 620 limit.
BS 7777 requires that the tanks are hydro tested to the maximum design product leveland allows a maximum shell plate thickness of 30 mm. However, the code does allow
thicknesses in excess of this figure with the purchaser's agreement. The new Eurocode
under preparation will probably allow a maximum shell thickness for 9 % nickel steel of
50 mm and partial height hydrotesting of the inner tank.
A benefit of the partial hydro test design for the 220,000 m3
tank is a material saving
of more than 700 tonnes of 9 % nickel steel. Further associated savings would be made on
labour and consumables due to the reduction in weld volumes.
Considering the extreme conditions at the Hammerfest LNG plant site in winter, it is
essential to have a weatherproof outer tank by the end of the construction window toallow work to continue inside the tank. In this case the steel roof would be exposed to the
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elements on the top of the tank and would be subjected to wind and snow loads. The
schedule requirement is to progress tank construction during the first summer to achieve a
weather tight envelope, permitting work to proceed inside the tank during the winter
months. The target is to complete the outer tank concrete roof, however in order to
mitigate for weather delays to the concreting, the steel roof should be designed to
accommodate the potential snow load in the event that the concreting operation is notcomplete.
8 CLOSING REMARKS
In December 2000, the Snhvit LNG project has passed an important milestone. The
license partners have selected the main engineering contractor and the LNG technology
licensor, and agreed to enter into the next phase of the project development, namely the
front-end design and engineering for the LNG plant.
Start-up of LNG production from the Snhvit fields is scheduled for October 2006.