Capacity and Technology for the Snohvit LNG Plant

8/3/2019 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.

Documents

Capacity and Technology for the Snohvit LNG Plant