Mini Mid-scale LNG PDF

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INII/M ID -S CALE LNG MIN

B ACKGROUND P APER

PREPARED BY TITLE:

NAME:

PRINCIPAL ENGINEER STRATEGIC TECHNOLOGIES

G.N.HUNTER

REVISION HISTORY REVISION

DETAILS:

DAT E:

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ISSUED

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D AT E :

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OCTOBER , 2006

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MINI/MID-SCALE LNG

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C ONTENTS 1.

INTRODUCTION

3

2.

LNG SUPPLY CHAIN

3

2.1

Gas Pre-treatment

4

2.2

Liquefaction Technologies Technologies

4

3.

MINI LNG

5

3.1

Peak-Shaving Peak-Shaving Plants

5

3.2

Base-Load Fuel Plants

6

3.3

Mini LNG Liquefier Technology

6

4.

BASE-LOAD MID-SCALE LNG

8

4.1

Mid-scale LNG Technology Providers

9

4.2

Mid-scale LNG Technology Selection

9

4.2.1

4.3

5.

Expander Plants

11

Discussions with Mid-scale Technology Vendors

12

4.3.1

Linde AG

12

4.3.2

Black & Veatch

14

4.3.3

ABB Lummus Global

15

4.3.4

Costain Oil, Gas & Process

18

4.3.5

Mustang Engineering

21

FLOATING LNG

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INTRODUCTION

This Background Paper on Mini/Mid-scale LNG has been assembled from information gathered from technical papers, trade journals, Internet, and discussion with several of the main mid-scale LNG technology providers. In our work to date in relation to gas field specific evaluation work that we have undertaken, we have concentrated on ‘mid-scale’ LNG facilities, therefore more information is provided herein regarding mid-scale technologies than ‘mini’ LNG. Initially our discussions with mid-scale LNG technology providers were in relation to their work on floating LNG developments. Only later did our focus change to onshore based facilities and as a result some of the narrative herein refers primarily to offshore floating LNG. For the purposes of this paper I have used the term ‘mini’ for plants less than 300,000tpa, ‘mid-scale’ for plants between 0.3 and 2Mtpa and ‘large’ for plants over 2.0Mtpa. In this document I have concentrated on providing background regarding mini and mid-scale LNG. Revert to us should you be also interested in large scale (e.g. current base-load capacity) LNG developments and we can provide background on these larger capacity facilities.

2.

LNG Supply Chain

The typical LNG supply chain is comprised of facilities similar to those below, of which only those within the “Base Load Liquefaction Plant” box will be discussed in this memorandum.


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Gas Pre-treatment

Natural gas requires removal of H 2S, CO2, COS, organic sulphur compounds, mercury and water prior to liquefaction in order to meet product specifications, avoid blockages and to prevent damage to process equipment. Condensate and LPG extraction may also be required. The cost of pre-treatment is dependent on the type and concentrations of the contaminants in the natural gas. Treating unit requirements are determined by the liquefaction unit requirements (water, CO 2), specifications of the LNG product (H 2S, COS, organic sulphur compounds), material protection (mercury) and environmental restrictions (SO2 and hydrocarbon emissions). In addition waste streams have also to fulfil minimum specifications. Pre-treatment upstream of a liquefaction unit traditionally consists of an acid gas removal step, in which CO 2 and sulphur compounds (H 2S, COS and mercaptans) are removed, a dehydration step and a mercury removal step. Where there are limitations on the SO 2 emissions, the removed sulphur components are recovered as elemental sulphur. Environmental limitations to hydrocarbon emissions can require incineration of CO 2 acid gas even in the absence of sulphur compounds. The mercury removal step can be positioned upstream of the acid gas removal or downstream of the dehydration step. Most of the operational base load LNG plants process feed gases with only low concentrations of CO 2, mercury and water. This type of gas requires the ‘minimum’ of treating, often comprising a CO 2 removal unit, molecular sieves for drying and a carbon bed for mercury removal. The relative capital investment for acid gas removal in a LNG plant increases significantly with increasing CO 2 content. At 2 mol% CO2 the acid gas unit represents 6% of the processing equipment cost but at 14 mol% CO 2 it represents 15% of the processing equipment cost. New developments such as membrane technologies are starting to be considered as an option for bulk removal of CO2 but solvent absorption remains the most cost effective treatment process for meeting LNG specifications. Further developments may change this in the future. The LNG product specification (e.g. heating value/Wobbe number etc) for the end market for the LNG will also determine the pre-treatment (and liquefaction) processing requirements.

2.2

Liquefaction Technologies

The current trend in LNG liquefaction plants is ‘bigger is better’ to capture the economy of scale. The high market demand for LNG and the availability of large quantities of ‘cheap’ gas, in locations such as Qatar, Trinidad, West Africa, Siberia and Egypt, distant from ready pipeline markets, is also driving train size upwards. To meet this demand for larger LNG trains, the providers of LNG technologies (including APCI, Phillips, Linde, Shell and Axens) have been engineering ever larger throughput trains. Note that aside from Linde the focus, and expertise, of these main-stream base-load LNG technology providers is nowadays on these large trains. While the publicity surrounding the economy of scale (e.g. lower per unit Capex cost) to be gained from developing large trains might lead to the assumption that a smaller scale LNG plant would be ‘swimming against the tide’, there are a number of LNG technology providers who have continued to develop and promote LNG liquefaction processes. While these companies accept that the per unit Capex of these mid-scale plants is higher than what can be achieved with trains that are much larger, they believe that mini and mid-scale plants can be economically developed. Although few LNG plants in these smaller capacities have been built in the last 20-30 years, most of the companies and technologies covered herein have either built plants or undertaken detailed studies (and several LSTK bids) for these sized plants.


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Liquefaction processes mainly use mechanical refrigeration, in which heat is transferred from the natural gas, through exchanger surfaces, to a separate closed loop refrigerant fluid. The refrigerant loop uses the cooling effect of fluid expansion, requiring work input via a compressor. Three main types of refrigeration cycle have been utilized for LNG; the cascade, mixed refrigerant and expander cycles. Each has its own merits and, depending on plant capacity, more than one type may be economical. There are a number of variants of each cycle, with some common features between them. For example, both the mixed refrigerant cycle and t he expander cycle have variants in which the feed gas is precooled by a conventional propane vapour compression cycle, which is its self, a feature of the cascade cycle. The choice of optimal process can vary based on site location, feed gas price and ambient conditions, and evaluation of alternative cycles may be necessary to determine the best economically over a development’s full life cycle.

3.

Mini LNG

Most mini LNG plants built to date have been used for peak-shaving. There is however a growing movement around the world to install mini base-load facilities to provide LNG for transport (usually for large trucks and buses) and remote communities. Another growing market for mini LNG plants is as a means of monetising landfill gas, coal seam methane and digester gas. Peak-shaving LNG plants typically have capacities of 10-400tpd, and operate 100-200 days/year, while baseload vehicle-fuel LNG plants, have similar capacities and operate 365 days/year.

3.1

Mini Peak-Shaving LNG Plants

The gas shortage in the 1970s drove the construction of many LNG peak-shaving plants. With these, pipeline operators liquefy natural gas when demand is low and store the LNG until demand is high. Storage is facilitated by the volume reduction accomplished through converting the natural gas to a liquid state. During periods of high demand, the LNG is vaporized and injected into either the gas transmission system or a distribution system. LNG peak shaving plants consist of two essential components: LNG storage tanks, and LNG liquefaction units. Natural gas from a pipeline is refrigerated in the liquefaction unit and stored in liquid form in an LNG tank. The stored LNG can be heated, vaporized and put back i nto the supply stream to meet demand peaks. LNG peak-shaving plants have significantly less LNG storage capability than an import terminal, but are located at strategic locations in the pipeline system. Storage of LNG enables a reliable supply of natural gas in areas where pipeline capacity limitations and weather conditions may cause supply and demand discrepancies, such as in the north-eastern United States, Europe and North Asia. There are more than 240 LNG peak-shaver facilities worldwide. Many peak-shave plants were built in the 1970’s and 1980’s, primarily in North America (where there are some 57) and Europe, and there is one such facility at Dandenong in Victoria. Even in Japan, which depends on large LNG imports for most of its natural gas supply, small-scale LNG systems are used for strategic distr ibution of landed gas among the islands of its archipelago.


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Mini Base-Load LNG Plants

The liquefier and storage tank technology used in peak-shave plants is fundamentally directly applicable to small-scale ‘base-load‘ plants. The main difference being the relationship between the liquefaction unit production rate and the storage volume (peak-shaving facilities are designed to slowly fill and quickly empty the storage tank), with base-load plants typically operating their liquefaction continuously. Around the world there are a number of mini base-load LNG plants, of a liquefaction plant size more typical of peak-shave units, but supplying base-load LNG for transport fuel or to remote communities. Recent examples include: •

•

•

3.3

The recent award of contract to Linde by Wesfarmers for a 175tonne per day (64,000tpa) facility to be constructed at Kwinana (south of Perth). This facility will provide LNG by truck as fuel for several mines in Western Australia. The 350 tons per day (128,000tpa) Praxair facility in Brazil. This facility provides LNG by truck to remote satellite storage system of Brazil not serviced by gas pipeline. I believe this is a Black&Veatch process. The EDL facility at Karratha in Western Australia (200tonne per day – 73,000tpa) and the facility operating in China (130tonne per day - 47,000tpa). These serve a similar purpose to the Praxair plant. Kryopak in New Braunfels, Texas has provided these as packaged plants.

Mini LNG Liquefier Technology

Liquefier designs have been adapted in small-scale liquefaction systems to make and store lesser amounts of LNG. These mini liquefaction facilities are usually relatively small, typically less than 100,000 tons per annum (270tonne per day) capacity. Following are suppliers of peak-shave size LNG plants: • • • • • • • • • • • • • •

Chicago Bridge & Iron Co. (USA). Black & Veatch Pritchard (USA). Chart Industries Inc. (USA). KryoPak Inc. (USA). Linde AG (Germany). Costain (UK). Hamworthy KSE (Norway). Air Products and Chemicals Inc. (USA). BOC (UK). GTI – Gas Technology Institute (USA). INL - Idaho National Laboratory ( USA). Cryofuels Systems (USA). Prometheus (USA). Tractebel (Germany).

The following are photographs of a variety of peak-shave and baseload mini LNG facilities.


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A small peak-shaving plant in Japan:

The Memphis LNG peak-shaving facility designed and built by CB&I (this has a 5.5mmscfd liquefaction rate and 150mmscfd send out rate):


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The 130tpd Kryopak designed and constructed base-load LNG facility in China:

A 10,000gpd vehicle transport LNG facility in Sacramento, California using INL technology:

4.

Base-load Mid-scale LNG

There are a number of liquefaction technologies which might be appropriate for a development in the 0.3 to 2.0Mtpa mid-scale capacity range. In this size range we can select either scaled down 1960s ‘base-load’


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cascade or mixed refrigerant technology or scaled up ‘peak-shaving’ technology based on turbo-expander technology.

4.1

Mid-scale LNG Technology Providers

While there is no doubt that a Bechtel or a KBR could execute a mid-scale LNG plant (using the Phillips Optimised Cascade or APCI process respectively), this size range is outside of the area of interest of these companies and their technology vendors. We were looking for companies that were ‘right sized’ for mid-scale LNG - having the technical expertise, the resources and the desire to develop export facilities in this size range. From desk top evaluations of companies professing to have mid-scale LNG credentials it was apparent that there are a number of companies with the technology and experience, and the following mid-scale LNG technology providers were visited regarding their LNG liquefaction technologies and LNG development capabilities: • • • • •

Linde (Munich) Black & Veatch (Kansas City) ABB Lummus Global (Houston) Costain (Manchester) Mustang (Houston)

From information gained during these visits the top three companies (ranked in a weighted evaluation) are recommended for further consideration were we to progress a mid-scale LNG development. Costain is also well credentialed, while Mustang’s concepts are less developed. Whereas for offshore floating LNG there are space and weight incentives to use turbo expander based liquefaction technology, the requirements for an onshore LNG development are different and consideration could be given to using a small cascade (like Phillips’ original Alaskan LNG plant) or mixed refrigerant (similar to Linde’s Chinese project) liquefaction process. As these latter processes are more efficient than turbo expander technologies (even when compared with the advanced double nitrogen expander plants proposed by Costain and ABB Lummus Global), a thorough technical and economic comparison would be required to determine the most suitable process route. A number of companies (including ABB Lummus Global, Costain and Mustang) have been considering mid-scale LNG development (both onshore and offshore) using multiple smaller 300,000 to 600,000tpa trains, drawing on experience from peak-shaving technology. Linde (and Costain as well, in parallel with their work on expander plants for floating offshore LNG) have been developing mid-scale single train LNG liquefaction based on the mixed refrigerant cycle, drawing on experience with large base load units but using a single gas turbine driver. It costs a lot and takes considerable time and resources to develop concepts such as these into bankable projects. I have commented below, as to where I believe they are in terms of technical development, and whether the companies have invested sufficient $ and time into their concepts to develop their MLNG technologies to the point that an operator would be prepared/able to proceed with a project to FEED.

4.2

Mid-scale LNG Technology Selection

There are pros and cons for each of the liquefaction technologies. Liquefaction cycles vary in both sophistication and power consumption. Choosing the optimum cycle is crucial to reducing plant capital cost as reduction in liquefier costs also reduces utilities and offsites costs. The choice of liquefaction cycle depends on many factors of which the major ones are:


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MINI/MID-SCALE LNG

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Revision 0

Machinery configuration and available drivers Specific power requirement (affecting machinery capital cost and operating cost) NGL recovery or nitrogen rejection requirement Heat exchanger type and surface area Required flexibility Ease of operation/start-up/shutdown Space and weight requirements (very important for floating LNG)

The following table considers each of the main processes and rates them against key criteria: CRITERIA

CASCADE

MRC

EXPANDER

Uses proven technology

Yes

Yes

Yes

Overall space requirement

High

Moderate

Low

Refrigerant storage hazard

Yes

No

No

Simplicity of operation

Moderate

Moderate

High

Ease of startup/shutdown

Moderate

Low

High

Flexibility to feed gas changes

High

Moderate

High

Efficiency

High

High

Low

Total Capital Cost

High

Moderate

Low

All of these issues should be considered in process technology selection. Machinery selection is especially important and normally plant capacity is optimized based on machine performance. The train capacity of some of these plants, although labelled as mid-scale, are in fact of similar size to the original late 1960s LNG trains such as the 1.15Mtpa Phillips Alaskan LNG plant and the circa 0.6Mtpa initial Libyan and Algerian trains. The following photograph is the Phillips Kenai LNG plant which uses the Phillips cascade process. This started up in 1969 at 1.15mmtpa and is now operating at 1.5mmtpa. When completed in 1969, the capacity of this plant was regarded as world-scale, whereas today its capacity would only regarded as mid-scale:


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Cascade and mixed refrigerant (MRC) processes are more efficient, however these are also more complex. An ABB Lummus Global study showed that for a similar capacity train size, the equipment count for these technologies was 40% higher than an almost as efficient dual turbo expander process. Some companies therefore propose using turboexpander technologies, with centrifugal compressors and brazed aluminium heat exchangers (BAHX), with both ABBLG and Costain selecting dual expander methane/nitrogen cycle units. As there are limitations on the currently available sizes of expanders/compressor drivers/BAHXs, for a 1mmtpa plant Mustang propose three trains while Costain and ABBLG propose two trains to keep individual equipment items within existing size ranges. Costain advised that they believed that it was possible at present to design a single train up to 0.65mmtpa utilising existing equipment. Both Costain and ABBLG stated that they have developed their turboexpander cycle processes to the point that these have similar efficiencies (in terms of specific energy – kW/ton of LNG) to mixed refrigerant processes.

4.2.1

Expander Plants

In its simplest form, refrigeration for the expander cycle is provided by compression and work-expansion of a single component gas stream. High pressure cycle gas is cooled in counter-current heat exchange with returning cold cycle gas. At an appropriate temperature, the cycle gas is work-expanded, reducing its temperature to a lower temperature than by expansion through a Joule-Thomson valve. Useful work is generated and is usually recovered through a booster-compressor brake, which supplements the main cycle compressor. The cold, low pressure gas stream from the expander is returned through various stages of heat exchange where its refrigeration is given up to the incoming natural gas and incoming cycle gas. The warmed cycle gas is re-compressed by the main cycle compressor and booster-compressor. The refrigerant cycle gas can be either methane or nitrogen. Nitrogen permits sub-cooling of the natural gas to temperatures low enough to eliminate flashing on let-down of the LNG. Expander cycles have a number of advantages over both cascade and mixed refrigerant cycles. They enable rapid and simple start-up and shut-down which is important when frequent shut-downs are anticipated, such as on peak-shave plants. Because the refrigerant is always gaseous and the heat exchangers operate with relatively wide temperature differences, the process tolerates changes in feed gas composition with minimal


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requirements for change of the refrigerant circuit. Temperature control is not as crucial as for mixed refrigerant plants and cycle performance is more stable. Because the cycle fluid is maintained in the gaseous phase, any problems of distributing vapour and liquid phases uniformly into the heat exchanger are eliminated. Two-phase distributors are thus avoided and this, along with the small heat exchangers, results in a relatively small cold box. The single major disadvantage of the expander cycle is its relatively high power consumption, compared with the cascade and mixed refrigerant cycles. In small plants the simplicity of the cycle can make up for the high power consumption but the expander cycle struggles to be competitive for larger onshore facilities. The basic single expander cycle can be modified to increase its efficiency. For example, power consumption can be reduced by approximately 20% by natural gas pre-cooling with a conventional vapour compression cycle, typically using propane. This introduces extra complexity but can be cost-effective if the additional equipment cost can be offset by the reduction in size and cost of the cycle machinery. An alternative to propane pre-cooling is to employ two expanders, operating over different temperature levels. This has been conventional practice in the liquefaction of nitrogen and oxygen for over twenty years. Two expanders allow closer matching of the composite curves than with a single expander, giving reduced temperature driving forces and higher thermodynamic efficiency. Power consumption is similar to a pre-cooled single expander cycle but without the need of a separate refrigeration system.

4.3

Discussions with Mid-scale Technology Vendors

The following are notes regarding the discussions held with Linde, Costain, ABB Lummus Global, Black&Veatch and Mustang :

4.3.1

Linde AG

Linde Engineering based in Munich (>4200 employees worldwide) is part of the wider Linde group contributing €2.9 billion (in 2005) to Group sales (exceeding €10 billion). Linde is well established in providing small scale LNG peak shaving (with 5 plants, starting with their first LNG peak shaver in 1972), base load (with 4 very small plants plus Xinjiang and Snovit) and satellite (with 7 small plants) to the industry. Additionally, they manufacture cryogenic exchangers (both brazed aluminium heat exchangers and spiral wound heat exchangers) and have done so for decades. Linde pioneered spiral wound HX’s in early 1900s and lost out to APCI in 1970s. Linde spiral wound heat exchangers are in service or planned on many worldscale LNG trains, e.g. NWS, Sakhalin, Egypt, and Snohvit. Their flagship LNG project is the Statoil-Linde process 4.3Mmtpa Snohvit LNG project currently underway and due for commissioning mid-2007. Their next biggest plant constructed is the 0.43Mmtpa Xinjiang Phase 1 plant in China and like Black & Veatch they have submitted a LSTK bid for the ~0.8Mmtpa Phase II expansion of this. Their business model is to market their patented technologies from early concept through to implementation. Linde has extremely good process plant experience but concedes that they would prefer not to handle the tank and jetty aspects of an LNG development. Linde is highly experienced with cryogenic processing technologies (to be expected for a company whose founder Karl Linde in 1873 invented the first mechanical refrigeration), with many decades of ethylene, gas processing, air separation and LNG experience. They have traditionally been a supplier of peak shaving LNG plants (recently in JV with BOC) and are co-developer of the Statoil/Linde LNG liquefaction technology being utilised for the Statoil Snovit LNG development in Norway.


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Of real interest to us, Linde were the design contractor for a 430,000tpa small base load LNG plant in China (which started up in 2004). The production capacity of the plant is 1,500,000 m3 (n)/d with an expected onstream time of 330 days per year. The design hourly liquefaction capacity is 54t/h, which is equivalent to approx. 430,000 ton/year. The plant is about three times larger than the largest existing peak-shaving plants, but about one third of the capacity of existing small base-load plants. This plant consists of natural gas treatment and liquefaction, LNG storage tank a nd LNG distribution system. The storage capacity is 30,000 m3 in liquid form of LNG based on a 10 day storage capacity. The LNG send-out and distribution system capacity meets the requirement of loading 100 trucks/ movable containers within 16 hours. The liquefaction process is based on a high efficiency single closed mixed refrigerant cycle. The feed natural gas has a low pressure at battery limit, which is too low for an efficient liquefaction process. Therefore the natural gas is compressed in three compressor stages after removal of solid and liquid particles in a separator. The natural gas is cooled, liquefied and sub-cooled in a spiral wound heat exchanger by a single closed mixed refrigerant cycle. This cycle provides cold temperature by Joule-Thompson expansion at three different pressure levels. The refrigerant is compressed in a 3-stage-turbocompressor, which is driven by a gas turbine. In order to enhance plant efficiency the waste heat from the gas turbine is recovered by heating a hot oil cycle, which covers the heating requirements of the process plant. The LNG from the liquefaction unit is sent to the storage tank via the tank filling line. The tank is filled continuously during operation of the liquefaction system at a filling rate of about 110m 3 /h. During 16 hours per day a continuous send out operation to the truck and container filling operates. For send-out operation two sub-merged in-tank pumps are installed, each designed for 320 m 3 / h capacity. This facility is located on a plot sized 585metres x 490metres (or about 30hectares). Unlike the expander based technologies, this China LNG facility utilises a mixed refrigerant process. While this would need to be confirmed with Linde, I believe that this process has the potential to be scaled up from 430,000tpa to around 1.0mmtpa capacity (as a single train plant). A photograph of the China facility:


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A 3D model graphic of the China facility:

4.3.2

Black & Veatch

Black & Veatch based in Kansas City, has approximately 7,000 employees with $2billion p.a. revenue and conducts projects in the USA and worldwide, primarily relating to water treatment and power. The Energy group has ~ 1200 employees and the Gas, Oil, Chemical group has an annual turnover of ~$360million. They have a close relationship with Quest (Norman, Oklahoma) who they utilise for their engineering safety studies support. They have an alliance with GHD in Australia who they regard as consultants rather than EPC contractors. They typically use MHI for large tanks. B&V through Pritchard has 50 years of LNG experience, and they have been involved in many of the industry’s “Firsts”. B&V has engineered and constructed some 14 operating LNG liquefaction installations with a further 8 under contract and in various stages of execution. A further 2 LNG liquefaction plants are tendered with award pending. These 24 plants include 20 using the PRICO process, 3 cascade process and 1 expander process. B&V has their own developed PRICO process (obtained through acquisition of Pritchard) which was used for two of the initial Skikda, Algeria base load LNG trains and has more recently been implemented in smaller peak shaver plants. B&V mentioned a Mobil study which evaluated PRICO against the APCI process and indicated 3% efficiency loss – could be as high as 6% per Brian Price. PRICO process claimed to manage variations in feedstock composition and temperature. Compressor power requirement typically 350-500 hp (260-375kW) per mmscfd of net LNG. Main cryogenic HX (brazed aluminium) envisaged for 1mmtpa capacity (~8m X 8m X 12m dimension) with estimated 180t lift. B&V are enthusiastic to re-enter the mid-scale LNG market as a technology provider. B&V scoped a floating LNG facility with IHI and Kvaerner during mid 1990s. Also did a 1mmtpa PNG study for BP in 1990s.


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They developed a 2mmtpa FEED study for an Enron LNG plant in Venezuela and prepared a LSTK bid for this prior to Enron’s collapse. The ‘all-in’ price included a 160,000 t single containment tank (for 135,000 t ships), single bed MRU, BASF activated amine for CO2 removal, USD 50MM for jetty/dredging. Also have bid (still awaiting award) for Phase II (approx. 0.8mmtpa) LNG plant at Xinjiang in China where Phase 1 (0.43mmtpa LNG) is a Linde design (see Linde visit report). We recently met with Perth based Liquefied Natural Gas Ltd regarding their proposed Padang LNG export development on Sulawesi Island in Indonesia, for which they now plan to use the B&V PRICO process for this 3 train 2.3Mtpa (e.g. approx 800,000tpa per train) facility. This is a depiction of the Enron facility:

4.3.3

ABB Lummus Global

ABB Lummus Global (ABBLG) is the process plant subsidiary of ABB. They have strong technology capabilities, particularly cryogenics (nitrogen removal, NGL recovery and ethylene plants in particular) but do not have project experience specifically with LNG. ABBLG has 4,000+ plus process plant staff working in 9 offices worldwide and they have executed more than 6,300 projects in over 70 countries. They are well resourced for undertaking front end engineering activities, with about 300 staff working in this area in Houston, Bloomfield and Den Hague. ABBLG are a leading process technology developer and they are keen to establish themselves as a contender for mid-scale LNG developments. They have been actively promoting their Niche LNG floating LNG concepts. They are looking to utilise their leading edge ethylene refrigeration expertise and experience to develop their floating Niche LNG, with a mixed refrigerant Niche MR LNG concept being worked, although at this stage they would not discriminate between niche LNG turbo expander (developed for 2Mtpa) or mixed refrigerant concepts.


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ABB Lummus Global (ABBLG) have developed their floating LNG concept titled NicheLNG FPSO in conjunction with a number of other companies, including their fellow ABB company Randall Gas Technologies for turboexpander gas processing and SBM (Single Buoy Moorings) for the marine side. They have been working on this concept since 1997 and the technical work has advanced over the past two years to the point that ABB believe that NicheLNG is now a commercial proposition (in terms of its technology). ABBLG is a highly proficient developer of oil , gas and chemical process technologies (for instance some 7 0-80% of the world’s installed ethylene capacity utilises their technologies) and a very experienced EPC contractor. In addition to ABBLG’s broad process and EPC experience, Randall have designed more than 180 cryogenic turboexpander NGL extraction facilities, and SBM are one of the world’s most experienced FPSO owner/operators (as well ABBLG’s Hague office has a strong marine group built up with staff hired from SBM and Bluewater), so the combined companies defi nitely have the expertise to develop floating LNG. The technical work carried by ABB to date has been recognised by the class society ABS which has granted Approval in Principle for the NicheLNG concept. This was a major milestone for floating LNG in general and ABB’s concept in particular. In addition to carrying out paid studies for a number of companies ABB have themselves spent >US$0.5million to date on NicheLNG technologies. Most of the technological features regarding liquefaction, storage and vessel substructure appear to be proven. In 2004 ABBLG carried out a detailed study for a three train 1.6mmtpa floating LNG facility using their NicheLNG concept for Murphy’s Kikeh development off Sabah, and it is this development that is shown in recent 3D CAD views advertising NicheLNG, and most of the detailed information they provided to me was from the Murphy Kikeh study. ABBLG’s work on NicheLNG has targeted stranded gas fields capable of supporting an LNG development up to some 1.5mmtpa and for the FPSO based version they have concentrated on remote offshore fields with environmental conditions requiring a turret mooring. This is how the overall NicheLNG concept appears:

From their work to date ABBLG has identified that cheap gas (

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scale LNG (and CNG) is the Husky Energy White Rose field, where the associated gas is being reinjected at a cost. ABBLG have carried out work on NicheLNG in a number of phases; •

•

•

Process Development – current base load LNG liquefaction processes are not suitable for small scale offshore LNG so ABB’s focus between 1997 and 2002 was on small/mid-scale liquefaction process technologies suitable for offshore/floating use, culminating in a number of US patents being awarded for turboexpander based mid-scale LNG processes. Some of the features of these processes (compared with conventional LNG processes) are; fewer pieces of equipment, smaller footprint, reduced weight, no liquid refrigerants, less sensitive to motions, simplicity of operation, higher reliability, minimal flare requirements, higher level of safety and high degree of modularisation. From this work the ABB Dual Expander Methane/Nitrogen Process was selected. Their conclusions regarding the liquefaction process are almost identical to those of Costain.

Phase 1 – FPSO Concept Development – their work program in 2003/4 entailed; topsides definition engineering, systems marinization (consideration of both motions and materials), LNG tankage and FPSO functional specifications, LNG offloading systems and concept safety evaluation. For the LNG tankage ABB/SBM favour the IHO SPB prismatic design which is structurally strong, is inherently superior to membrane type tanks for sloshing of the LNG (with partially filled tanks) and also provides a flat open deck for process modules.

Phase 2 – Systems Development – their work program in 2004 entailed; extended topsides engineering definition (incl. preliminary P&IDS, equipment specifications, layouts, piping studies), conceptual FPSO hull configurations and designs, global analysis of vessel mooring and motion envelopes, shortlisting of LNG offloading systems, and support studies for “Approval in Principle” by ABS (including safety assessments). All utilities have been scoped, laid out and costed. Consideration was also given to placement of equipment on the FPSO deck to locate hydrocarbon inventories etc away from accommodation.

As noted above, most of ABBLG’s recent work is based around the Murphy Kikeh development. For this the feed gas was associated gas which had already been partially treated although the gas was reasonably rich. Condensate was to be returned to the ‘oil FPSO’ while LPGs were to be stored and shipped from the ‘LNG FPSO’. This facility was to process some 280mmscfd feed gas, and produce approx. 1.6mmtpa of LNG and 400mtpa of LPG/condensate. The feed treatment facilities ahead of the LNG liquefaction therefore are comprehensive including separation, condensate stabilisation, gas filtration, amine plant (for CO2 removal), MOL sieves for dehydration, mercury guard beds and LPG extraction (C3/C4 mix). Therefore they have covered most processing facilities which may be required for a gas only development. In terms of the work that they have completed to date and their understanding of the issues associated with developing a mid-scale floating LNG facility, ABB provide the most confidence. Their resources, their depth of knowledge (based both on the specific work they have carried out, as well as their historical knowledge of the subjects involved) is superior and they have taken their NicheLNG concept far further than the others. In the process they have addressed or are addressing the known technical issues surrounding floating (versus onshore based) LNG.


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The following graphic is for the topsides of the Niche LNG, which represents a 1.6mmtpa double expander plant with the liquefaction made up of three identical trains. Although shown located on a ship, this approximates the processing facilities that an onshore development would consist of, with double expander type technology:

4.3.4

Costain Oil, Gas & Process

Costain is based in Manchester and (like ABB) has been active in promoting floating LNG as a vehicle for establishing themselves in providing engineering services to the LNG industry. Like ABB they have not yet executed an LNG project but have however been enlisted by clients on various LNG pre-FEED studies. Clients include BP, BG, Shell, ConocoPhillips, BHPBilliton and Methanol Australia. The process plant group Costain Oil, Gas & Process is part of the Costain Group which employs some 3,300 staff as part of a US$1.6billion per annum business. Costain is not bound to any specific technology and would consider turbo expander or mixed refrigerant technologies. Costain advised that they have been involved in 15 LNG peak-shaving installations (6 mixed refrigerant and 9 expander plants). Costain’s front end solutions group comprises 20-30 staff. They would typically use Advantica for their safety risk support. The breadth of Costain’s greater business qualifies them for managing the full scope including jetty and tankage aspects. Costain is an experienced UK based company offering both specialist gas processing expertise (including LNG) and full design/supply/construction services. For over 55 years they have been designing and constructing gas processing plants around the world and their involvement in LNG has come about through their long term work on cryogenic processing plants, including small scale LNG, nitrogen rejection and other cold processes. Costain has been evaluating floating LNG for some 20 years and interestingly in 1989 they carried out an LNG study for the Pandora gas field in the Gulf of Papua. They have completed some 15 or so small scale LNG plants (primarily peak shaving) and have been involved in studies of a number of larger and floating LNG facilities including; BHPP Bayu-Undan cLNG (on a GBS), Methanol Australia’s Tassie Shoal LNG (also on a GBS), and a floating LNG FPSO concept (in conjunction with Moss Maritime) for El Paso. They have also worked on floating LNG FSRU facilities, and have been working on BHPBilliton’s Cabrillo Port LNG import terminal project.


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In the course of their work on small scale LNG, other cryogenic processes, and larger scale LNG studies Costain (or their JV partners) has considered most of the technological features regarding liquefaction, storage and vessel substructure, and are confident that these have been proven – sufficiently at least to be able to undertake screening quality studies. For the El Paso work, due to the involvement of Moss, the LNG storage tanks were of the Moss spherical type and they carried out testing to evaluate the impact of sloshing within the tanks (note that Moss tanks are not really suitable for a floating LNG FPSO as they sterilize deck space required for processing facilities and are prone to sloshing when partially filled). They also undertook tank testing of models of the floating facility to evaluate side-by-side offloading of LNG to LNG carriers. Only well-proven, conventional processes and equipment were considered and for the processing plant, Costain worked to utilise well proven and inherently safe equipment. The liquefaction process selected was a methane/nitrogen expander plant. These processes have been used for peak shaving plants, and although the capacity of a large peak shaving plant is 150-200tonne/day (the largest being around 400tonne/day or 150,000tpa) a company such as Costain has the in-house know-how to scale up to the 300,000 to 600,000tpa train size required. Turbo-expander refrigeration cycles are well proven for cryogenic liquefaction including LNG peak-shaving and large-scale industrial gas liquefiers. Compression and work-expansion of a suitable fluid, typically nitrogen, generates refrigeration. The cycle gas is boosted in the brake-end of the expander. If only one stage of workexpansion is employed, then power consumption is excessive and only justifiable for small plant capacities. Initial work on offshore LNG production considered pre-cooling by Freon (3) but subsequent work has concentrated on the use of a second expander. Both machines can operate over the same pressure ratio but at different temperatures or alternatively the ‘cold end’ expander operates over a much larger pressure ratio. The two machines use a common skid. Two expanders enable the natural gas to be cooled and condensed at small temperature differences, so heat exchanger size increases but specific power reduces. Mechanical refrigeration, based on propane, can reduce power consumption by cooling the feed gas and also chilling the cooling water, so that the cycle compressor discharge temperature can be reduced. However, propane introduces the need for storage of flammable hydrocarbons. The increased complexity, reduced overall reliability and need for refrigerant storage are important disadvantages in consideration of pre-cooling, though there are grounds for reconsidering it on larger facilities. Expander cycles have a number of advantages over both cascade and mixed refrigerant cycles. They enable rapid and simple start-up and shut-down which is important when frequent shut-downs are anticipated. Because the refrigerant is always gaseous and the heat exchangers operate with relatively wide temperature differences, the process tolerates changes in feed gas composition with minimal requirements for change of the refrigerant circuit. Temperature control is not as crucial as for mixed refrigerant plants and cycle performance is more stable. The single major disadvantage of the expander cycle is its relatively high power consumption, compared with the cascade and mixed refrigerant cycles. In small plants the simplicity of the cycle can make up for the high power consumption but the expander cycle struggles to be competitive for larger onshore facilities. However, offshore, the expander cycle has benefits for any size plant. For liquefaction offshore, the criteria for technology selection differ from those for onshore liquefaction and this leads to an interesting conclusion as to the best choice of technology. The most important criteria offshore is to minimise the space required to give a safe plant, due to the effect on overall vessel size and overall cost. Offshore plants must also be insensitive to vessel motion, simple to operate and flexible to changes in feed gas rate or composition. They may be required to shut-down quickly in bad weather and should offer rapid start-up after such shut-downs or when moving between fields. In contrast to onshore liquefaction where energy efficiency has a large effect on overall cost, energy efficiency is of secondary importance offshore.


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The selected technology for their LNG FPSO design is the double nitrogen expander cycle. Expander cycles offer considerable advantages for offshore liquefaction and the use of two expanders avoids the need for precooling by mechanical refrigeration with distinct benefits in terms of reliability, space and avoidance of refrigerant storage. The double nitrogen expander cycle requires more power than more complex cycles but the simplicity of the process makes it cheaper and safer. A comprehensive evaluation of the major criteria for offshore liquefaction has shown this refrigeration cycle to be optimal. A major benefit of using nitrogen as the cycle fluid is that it is inherently safe. Storage of hazardous hydrocarbons adjacent to, or within, the processing plant is avoided and there is no need for major hydrocarbon flaring if the refrigerant compressor trips. The expander cycle is simple and has fewer items of equipment than alternative refrigeration cycles. This leads to reduced plot space and facilitates modularization. Expanders are highly reliable on nitrogen duty and maintenance requirements are minimal. Nitrogen is maintained in the gaseous phase at all points of the refrigeration cycle, so distribution in the heat exchangers is not a concern, unlike other refrigeration cycles. As a result, plant performance is much less sensitive to vessel movement. The nitrogen expander design is flexible to changes in feed gas conditions and requires minimal operator intervention. Control of specific temperatures is not as important as with mixed refrigerant cycles and the process is inherently more stable and robust. An important attribute is the ability to easily and quickly shutdown in a safe and controlled manner and to start-up quickly; a plant can be started from a cold condition in no more than an hour, unlike a mixed refrigerant plant that may require many hours to reach stable performance. There are a number of advantages of these expander processes in that they are safer and more compact due to; no liquid refrigerants (the expander cycle refrigerant is always in the gaseous phase. Methane would be sourced from the gas stream, while nitrogen would be generated on-board and is required anyway for blanketing of the LNG tanks), their simplicity and small footprint (the expander cycle gives a compact facility with the liquefaction plant, utilities and storage all in close proximity, minimising ship size and therefore cost). The space requirements for the cascade and MRC cycle are greater in comparison because of the need for hydrocarbon refrigerant storage tanks. Costain believes that they would be able to achieve liquefaction efficiencies approaching those of the large LNG processes such as Phillips Cascade and APCI mixed refrigerant. In addition to being compact and inherently safe, the cold box is relatively short and no fractionation columns are required, so limiting the effect of vessel motion. As there are current limitations on the size of some of the equipment items (such as turbo-expanders, compressors, gas turbines (aero-derivative) and brazed aluminium heat exchangers), Costain has worked to keep the equipment within proven sizes. There are also advantages using multiple trains which benefit turndown flexibility and availability, by enabling individual trains to be shutdown/started as required to suit production and maintenance activities. Use of electric motor driven compressors is another innovation that Costain has been considering. In the work that Costain has undertaken on mid-scale floating LNG they have considered; pre-treatment specification and design (incl. removal of NGLs), liquefaction process selection (considering the full range of cascade, mixed refrigerant cycle and expander processes available), compressor/expander/driver optimisation, reliability and operability assessment, development of storage and marine strategy, value engineering and cost reduction Equipment layout studies were carried out (to locate the pre-treatment, LNG liquefaction and utilities optimally, and safely, on the FPSO deck) and a coarse safety assessment of the floating LNG concept was carried by DnV and a preliminary QRA (Quantitative Risk Assessment) was also undertaken. Cargo transfer and ship motions studies were also carried out. In terms of the work that they have completed to date and their understanding of the issues associated with developing a mid-scale floating LNG facility, Costain instil a high level of confidence. Their depth of knowledge (based both on the specific work they have carried out, as well as their historical knowledge of the subjects


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involved) is sound, particularly the process side. They have addressed most of the known technical issues surrounding floating (versus onshore based) LNG.

4.3.5

Mustang Engineering

Mustang is marketing a concept titled Smart LNG TM which incorporates a number of interesting technological features with regard to the LNG storage and re-gasification. Although Santos workshopped this with them in Adelaide, little was known about the technical work that Mustang have undertaken to underpin their proposals. From the information that Mustang did provide for their proposed liquefaction process technology, this would be a dual turbo-expander plant using methane for refrigerant. They have sized these in 50mmscfd (approx. 333,000tpa of LNG product) units, so a nominal 1mmtpa development would have three trains. For the LNG storage (both offshore and onshore) Mustang have proposed using ‘bullet’ type tanks similar to those used for LPG. These are large (38’ diameter and 176’ long) 9% nickel vessels weighing 200tons each. This storage concept has been derived from the Ardjuna LPG storage barge that has been operating in Indonesia for the past 27years, originally developed by Arco. The sea conditions in the Java Sea northwest of Jakarta are benign. Ardjuna has 6 carbon steel bullets storing 60,000m3 of LPGs. This is a good analogue, however extending this concept to a larger turret moored, open sea, LNG production, accommodation, cryogenic storage (with say 140,000m3 of low temperature insulated and blanketed storage) and LNG offloading barge will not be without considerable unthought of technical challenges. While there don’t appear to be any major flaws in their concept (and for a near-shore or onshore mid-scale LNG liquefaction and storage facility this may be all workable), the bottom line is that no-one has built facilities such as this and there has been very little engineering carried by Mustang. Mustang is a highly competent engineering contractor however their forte is not process and technical development, it is detailed engineering. As noted above, it takes time and money to develop new concepts, and Mustang is looking for clients to fund the development. Several of the Mustang personnel involved in this LNG work are ex-Bechtel and in addition to LNG export facilities, they have been developing LNG re-gasification technology. This is a technology for which Mustang has carried out substantial engineering and testing work, and they have recently won a contract to provide their proprietary units for the upgrade of the existing Lake Charles LNG import terminal in Louisiana. In order of maturity of the concepts, Mustang’s is the least developed. Aside from high level concepts and generation of 3D views, Mustang has undertaken little engineering work to support their concept – compared with ABB, Linde and Costain who have carried out relatively detailed studies (as noted in their sections above). Mustang’s response to this is ‘trust us’. They noted that they have individuals on staff (mainly ex-Bechtel) who have extensive LNG experience and they also have access to experienced external consultants to provide the required naval architecture and concrete barge design/construction expertise (and for the barge and storage they are relying heavily on the Ardjuna LPG floating storage facility experience).

5.

Floating LNG

Many companies have been working on floating LNG concepts quite intensely over the past 5 or 6 years, but most have been trying to develop larger floating LNG liquefaction facilities. Some, such as Statoil’s Nnwa/Doro, Shell’s Sunrise and Kudu, and previous Mobil developments addressed offshore LNG facilities with world-scale throughputs of >5mmtpa. As well, many contractors such as IHI, Aker Kvaerner, Technip, Foster Wheeler and Halliburton KBR have also been studying world-scale capacity floating LNG concepts. There are also a number of other companies who


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are working on aspects of floating LNG facilities or equipment (incl. Saipem, SBM, Bluewater, Nexans, FMC, APL, BPP, US Hose). In relation to mid-scale floating LNG specifically, after meeting with each of the companies covered above it was evident that Mustang has concentrated on near-shore mid-scale LNG, while other companies including Costain, ABB and Linde have concentrated on deepwater floating LNG developments. Although the liquefaction components of offshore and onshore LNG are relatively interchangeable, the specific technology used will depend on which stranded gas field being considered (eg. offshore, near-shore or onshore), based on each company’s relative strengths. Most companies chose conceptually similar turboexpander technologies, with centrifugal compressors and brazed aluminium heat exchangers (BAHX), with both ABBLG and Costain selecting dual expander methane/nitrogen cycle units. As there are limitations on the currently available size of expanders/compressor drivers/BAHXs, for a 1mmtpa plant Mustang propose having three trains while Costain and ABBLG propose two trains to keep individual equipment items within existing size ranges. Costain indicated that it was possible at present to design a single train up to 0.65mmtpa utilising existing equipment. Both Costain and ABBLG stated that they have developed their turboexpander cycle processes to the point that these have similar efficiencies (in terms of specific energy – kW/ton of LNG) to mixed refrigerant processes. All the companies have sound concepts, however of the companies evaluated, in terms of the work that they have completed to date and their understanding of the issues associated with developing a mid-scale floating LNG facility, ABB provide the most confidence with Linde and Costain close behind and Mustang trailing. ABB’s resources exceed the others, their depth of knowledge (based both on the specific work they have carried out, as well as their historical knowledge of the subjects involved) is superior and they have taken their NicheLNG concept far further than have Linde, Costain or Mustang. The good news is that between the work carried out by Operators and the contractors, most of the perceived technical impediments to floating LNG, such as LNG STS (side to side) offloading, have either been resolved or work programs are underway to resolve. The question remains as to whether any of these contractors have invested sufficient $ and time into their proposals to develop their MLNG ‘technologies’ to the point that an operator would be prepared/able to proceed with a project to Pre-FEED. It costs a lot and takes considerable time to develop concepts such as these into bankable projects and history says that there will be technical challenges encountered along the way that haven’t been considered yet (and that will add substantial time and cost to any development). I have commented against each of the companies, as to where I believe they are in terms of technical development. In relation to the last point the Azure R&D Project was carried during 2000/2001. This was a JIP LNG study partially funded by the European Union, with technical and financial support from Shell, Total, Chevron, Texaco and Conoco. Some US$6.4million was expended over an 18 month period by the contractors and class societies involved. The Azure Project considered two different floating LNG scenarios, including a potential 1mmtpa West African development and a 3mmtpa South East Asian development. This information is pertinent mainly as an indication as to the time and money which can be involved in taking a floating LNG concept through to a ready for FEED stage.


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Mini Mid-scale LNG PDF

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