a competitive offshore lng scheme utilising a gravity base structure

A COMPETITIVE OFFSHORE LNG SCHEME UTILISING
A GRAVITY BASE STRUCTURE AND IMPROVED
NITROGEN CYCLE PROCESS
UN PROJET COMPETITIF DE GNL OFFSHORE UTILISANT
UNE STRUCTURE DE GRAVITE DE BASE ET UN PROCEDE
PERFECTIONE DE CYCLE DE NITROGENE
Chris Dubar
Senior Engineering Specialist
Timothy Forcey
Principal Process Engineer
Vaughan Humphreys
Senior Engineering Specialist
BHP Petroleum
120 Collins St, Melbourne, Victoria 3000, Australia
Dr. Hans Schmidt
Senior Process Engineer, Linde AG
Dr.-Carl-von-Linde-Strasse 6-14, D-82049
Hoellriegelskreuth/Germany
ABSTRACT
A feasible and economic means has been developed using proven technology
elements, to produce and export LNG from remote marginal gas fields. The cLNGTM
liquefaction process is introduced, which is particularly suitable for offshore
developments, on fixed or floating structures.
This paper addresses the specific design developed for the Bayu-Undan gas /
condensate field that is located offshore in the Timor Sea Zone of Cooperation between
Australia and Indonesia.
Key features of the Bayu-Undan design include:
•
the cLNGTM nitrogen cycle liquefaction process, developed from a process proven in
LNG peak-shaving operations, but with gas conversion efficiency similar to
conventional base-load plants;
2.4–1
•
a fixed concrete Gravity Base Structure, or man-made island, placed on the seabed
that supports all topsides facilities including the pre-stressed concrete full-containment
LNG storage tanks and cLNGTM plant;
•
conventional land-based-type LNG carrier mooring and loading facilities.
Detailed model testing, and safety and reliability studies confirm the future safe and
reliable operation of all aspects of the LNG facility. Detailed cost estimates confirm that
offshore LNG production in the range of two to three million tonnes per year is
competitive with larger land-based LNG facilities on a cost per tonne of LNG basis.
Sufficient design, safety review, and cost estimating work, along with independent
auditing, has been done to conclude that the cLNGTM process is ready for LNG base-load
applications that would result in the commercialisation of remote marginal gas fields.
RESUME
Un moyen faisable et économique a été développé en utilisant des éléments
technologiques prouvés pour produire et exporter le GNL des puits des gaz retirés et
marginaux. Le procédé cLNG™ de liquéfaction est introduit sur des structures stabilisées
ou flottantes et est particulièrement convenable pour des dèveloppements offshore.
Cette étude s’adresse au project développé spécifiquement pour le gaz de Bayu-Undan
domaine condensé qui est situé au large dans la zone de co-opération entre l’Australie et
l’Indonésie dans la mer du Timor.
Les traits clé du développement comprennent:
•
Le procédé cLNG™ de nitrogène cycle de liquéfaction, développé d’un procédé
prouvé dans l’opération GNL quand il y a des grandes demandes avec un changement
efficace de gaz semblable aux méthodes conventionelles;
•
Une structure de gravité de base fixe ou une île artificielle placé ou fond de la mer qui
supporte toutes les infrastructures et facilités, comprenant les réservoirs GNL qui sont
accentués par du béton;
•
Des moyens conventionnelles á terre de transpsortation GNL de mouillages et de
chargement.
Des tests de modèle détaillés des études de sûretés confirment la sûreté et la qualité de
l’opération sur toutes les aspects de la structure GNL. Des coûts estimés confirment que
la production du GNL au large est de 2 à 3 millions de tonnes par an et est compétitif avec
des plus grandes structures de GNL, à un coût par tonne de base de GNL. Des plans, des
revues de sûretés suffisants et des coûts estimés avec des vérifications indépendantes ont
été faites pour conclure que le procédé cLNGTM est prêt pour la commercialisation des
puits de gaz éloignés marginaux.
2.4–2
A COMPETITIVE OFFSHORE LNG SCHEME UTILISING
A GRAVITY BASE STRUCTURE AND IMPROVED
NITROGEN CYCLE PROCESS
THE POTENTIAL ADVANTAGES OF OFFSHORE LNG PRODUCTION
VERSUS ONSHORE
Over the past several years, BHP [1] and others [2-5] have investigated the
commercialisation of offshore static gas resources. Options studied for these fields include
methanol, synthetic fuels, and LNG. LNG production offshore, such as shown in Figure 1,
could have significant cost advantages over onshore, some of which are listed here.
cLNGTM PLANT
SEABED
GRAVITY BASE STRUCTURE
Figure 1 - cLNGTM Plant on
Gravity-Base-Structure in Shallow Water
An offshore facility would require only a short gas transmission pipeline, with minimal
gas transmission costs. Gas can be made available at higher pressure.
Compared with an onshore plant, no land is needed for the plant site, eliminating the
associated site development costs and environmental impacts. Costly infrastructure
development in remote areas is not required, such as community facilities, roads,
construction wharf, construction camps, or harbour facilities. The offshore facility may be
constructed at lower cost and with greater quality control at established fabrication yards,
rather than importing high cost labour to the remote onshore plant site.
Good quality seawater for process cooling is readily accessible offshore. Channel
dredging, a jetty, and extensive cryogenic piping for the transfer of LNG from storage to
the loading terminal is eliminated. For the offshore loading terminal, there are no LNG
carrier operations in crowded harbours, nor any associated delays. In some cases, the
2.4–3
offshore facility may be geographically closer to the customer, compared with the nearest
suitable onshore plant site, thereby reducing shipping costs.
cLNGTM DESIGN DEVELOPED FOR BAYU-UNDAN GAS RESOURCE
The Bayu-Undan gas / condensate resource is located in the Timor Sea Zone of
Cooperation (ZOC) between Australia and Indonesia which is shown in Figure 2.
I
INDONESIA
ZOC
AUSTRALIA
Figure 2 - Zone of Cooperation (ZOC)
The offshore cLNGTM design developed specifically for Bayu-Undan could have many
applications elsewhere around the world. The current upstream development plans for
Bayu-Undan call for a condensate and LPG stripping operation. Initially, a lean gas would
be re-injected into the reservoir until downstream gas utilisation facilities, of which
cLNGTM is one option, come on-line.
Weather conditions in the Timor Sea are dichotomous, that is, they are generally
benign, and yet are subject to relatively immature tropical cyclones. It is in this area that
BHP successfully pioneered the use of dis-connectable and purpose-built Floating
Production Storage and Off-loading (FPSO) oil facilities. These FPSO’s, specifically
developed for the cost effective commercialisation of marginal offshore oil fields, were
forerunners in the industry. FPSO’s are now common-place, even in far harsher weather
conditions than those of the Timor Sea.
Similar to the evolution of FPSO’s for the commercialisation of marginal oil fields,
cLNGTM technology is now ready to use for the commercialisation of marginal offshore
gas fields.
2.4–4
SHALLOW WATER SITES ARE SUITABLE FOR cLNGTM PLANTS
MOUNTED ON MAN-MADE ISLANDS
cLNGTM technology may one day be used on floating LNG facilities. However,
floating facilities require the future development of a safe and reliable cryogenic offloading system for the transfer of LNG from one floating vessel to another.
Fortunately for the near term, the availability of shallow water sites in the Timor Sea
near undeveloped gas resources [6], allows the cost-effective use of cLNGTM plants on
Gravity Base Structures (GBS). Such a man-made-island would sit firmly on the seabed.
This enables the use of conventional loading arms for LNG transfer. As shown in Figure 3,
no new LNG off-loading technology is required.
LOADING WITH
CONVENTIONAL
ARMS
Figure 3 - LNG Carrier Being Loaded with
Conventional Loading Arms from Fixed GBS
IMPROVED NITROGEN CYCLE PROCESS
Safety Considerations for Compact Offshore LNG Process
One of the critical aspects to consider in the selection of a liquefaction process for use
in an offshore environment is safety. Although conventional liquefaction processes
available today have been very successful in base-load plants, their extensive use of
hydrocarbon refrigerants makes them less than ideal for use offshore. These processes
have large inventories of liquefied hydrocarbon gases, contained at high pressure, which
would constitute a significant fire and explosion hazard for offshore applications.
2.4–5
A major concern is that such refrigerants could be involved in events such as
BLEVE’s (Boiling Liquid Expanding Vapour Explosions). These hazards are managed in
a land based plant by maintaining adequate separation distances between the equipment in
the process plant, storage and off-loading areas, adjacent trains and control room areas.
However, in an offshore plant it is not possible to maintain those same separation
distances without the offshore plant becoming prohibitively expensive.
A basic principle of loss prevention and process safety is that the designer should aim
to use small quantities of hazardous materials or substitute a less hazardous material if
possible [7,8]. Thus BHP considered the inherently safer nitrogen cycle process as a good
candidate for offshore LNG. By using nitrogen as the refrigerant, the inventories of
liquefied hydrocarbons contained in the process are greatly reduced. Furthermore, there
are fewer equipment items and systems handling flammable hydrocarbons, and
consequently fewer potential points for hazardous materials to leak from flanges,
compressor seals, etc. Each of these aspects reduces risk on the offshore LNG facility.
The nitrogen expander cycle process has been suggested by others for offshore LNG
production, [2,3] but it has generally been dismissed as being too inefficient for use in a
base-load LNG plant.
Description of Simple Nitrogen Cycle Process Used in LNG Peak-Shaving Plants
The base-load LNG technologies in use today are very efficient in terms of the
refrigeration power required to produce each tonne of LNG. On the other hand, in an
LNG peak-shaving plant, this high efficiency is not as important because the plant may
only run for part of the year and the plant capacity is much lower.
The simple nitrogen cycle process, as shown in Figure 4A, has been used successfully
in a number of these peak-shaving plants. A description of this process follows. As in any
LNG process, the natural gas supply to the plant passes through a pretreatment section
where carbon dioxide and water are removed. The gas is cooled, heavy hydrocarbons are
removed (if required), and then the gas is liquefied in a series of exchangers. The nitrogen
refrigerant is a gas (i.e., single-phase) at all times. The heat exchangers used are usually
aluminium plate-fin exchangers installed in a cold box. Because the heat transfer process is
much simpler than the complex two-phase heat transfer involved with mixed- refrigerant
based LNG technologies, the design of this equipment is relatively straightforward.
Cold refrigerant is generated by a nitrogen expander cycle in which compressed
nitrogen is pre-cooled in exchanger E1. Then the majority of the flow is expanded by
turbo-expander X2 which results in the required low temperature nitrogen stream. This
cold nitrogen is then used to provide the bulk cooling of the natural gas in exchangers E2
and E1. Optionally, a small stream of pre-cooled nitrogen is further cooled in exchanger
E2 and is then letdown in pressure through a valve to produce some very cold gas and / or
liquid nitrogen. This stream is used to provide the sub-cooling of the LNG in exchanger
E3. In some plants, methane is added to the nitrogen refrigerant to improve the efficiency
of the process. The warmed nitrogen leaving exchanger E1 is compressed by compressor
C1 and is further compressed by the booster compressor C2 driven by turbo-expander X2.
2.4–6
While other liquefaction processes such as the mixed-refrigerant cycle have been used
for recent peak-shaving plants, the nitrogen cycle process is well proven and is very simple
to operate. One Linde peak-shaving plant is designed for unattended operation, while
others operate unattended at night.
Figure 4A - Simple Nitrogen Cycle Process
for LNG Peak-Shaving Plant
Figure 4B - BHP Optimised N2 Cycle
Process for cLNG TM Base-Load Plant
C1
C1
Natural Gas
Natural Gas
Pretreatment
Section
Pretreatment
Section
E1
E1
Coolant
Coolant
Separation of
Heavy
Hydrocarbons
Separation of
Heavy
Hydrocarbons
E2
E2
X2/C2
X2/C2
Heavy
Hydrocarbons
Heavy
Hydrocarbons
E3
E3
X3/C3
LNG
LNG
The only change to the Simple Nitrogen Cycle is the addition of a second expander.
Figures 4A & 4B Simple & Optimised Nitrogen Cycle Processes
Inherently Safer Nitrogen Cycle Process Attractive for Offshore Use
The nitrogen cycle process has a number of attractions for offshore LNG production.
The simple design, using a single refrigeration cycle operating in the single phase gas
region, means that there are relatively few equipment items. The liquefaction section of the
plant consists of a single compressor, a turbo-expander, a cold box and three heat
exchangers for the compressor coolers. This reduces the complexity and space
requirements for the plant. No compressor suction or refrigerant surge drums are required,
nor their associated piping, valves and instrumentation.
cLNGTM Process Boosts Efficiency of Nitrogen Cycle for Base-Load Plants
The disadvantage of using this nitrogen cycle process for a much larger base-load
LNG plant is, however, the relatively low process efficiency of the cycle. Table 1 shows
that the refrigeration power requirement (per kmol of LNG liquefied) for a typical smallsize LNG peak-shaving plant using a nitrogen cycle (Case 1) is over three times that of a
base-load LNG plant using a mixed-refrigerant cycle (Case 4). It is clear that it would not
be competitive to use a nitrogen cycle with this process efficiency for a base-load LNG
plant. Furthermore, even if the large industrial ‘Frame 7’ gas turbine were used as the
compressor driver, the maximum throughput of each train would be rather small, because
of this poor efficiency. The low efficiency of the nitrogen cycle process used in peak2.4–7
shaving units is partly caused by the relatively low throughput of these units compared to
base-load plants, rather than being entirely due to the lower process efficiency of the
nitrogen cycle process itself. The efficiencies of the small rotating equipment used in peakshaving plants are significantly lower than those of the larger equipment that would be
used in a base-load plant. In addition, the feed gas pressure available to a peak-shaving
plant may also be lower than the 55 bar pressure typically used in a base-load plant. This
results in lower thermodynamic efficiency and contributes to the high refrigeration power
requirement of the process.
Table 1, Case 2 illustrates the improvement in efficiency if the simple nitrogen cycle
process was increased in size to a much larger capacity and the feed gas pressure increased
to 55 bar. Using typical efficiencies for large rotating machinery improves the cycle
efficiency to approx. 11 kW/kmol/hr. However this is still significantly more than for a
conventional mixed-refrigerant cycle.
Table 1 - Specific Power Requirements for Liquefaction Processes
Nitrogen Cycle Process
Case 1: Peak-Shaving Plant Simple Nitrogen Cycle
Case 2: Base-Load Plant Simple Nitrogen Cycle
Case 3: Base-Load Plant cLNGTM Process
Case 4: Base-Load Plant Propane Pre-Cooled Mixed Refrig
Feedgas
Pressure
(bara)
8.2
LNG
Power
Rate
Required
(kmol/hr)
(kW)
86
1,920
Specific
Power
(kW/kmol/hr)
22.3
55.0
6,267
68,565
10.9
55.0
6,267
47,659
7.6
55.0
-
-
~ 5.5 to 6.0
One significant inefficiency in the nitrogen cycle is the use of the expansion valve in
the nitrogen supply to the coldest exchanger. The adiabatic expansion across this valve
results in a loss of ability to produce work from this high pressure stream. In a small LNG
peak-shaving unit, this loss of work is quite small in absolute terms and attempting to
recover it is not justified. For the larger scale base-load plant however, the improved
nitrogen cycle that BHP and Linde have developed recovers this lost work by using a
second, so-called “cold” expander in place of the expansion valve. This results in a
significant improvement in efficiency as shown in Table 1, Case 3 above. Figure 4B shows
the basic difference in configuration between the proven, simple nitrogen cycle process
used in peak-shaving plants and the optimised nitrogen cycle used in the cLNGTM process.
Pre-cooling the feed gas via a small auxiliary refrigeration cycle is another known way
of increasing the efficiency of the nitrogen cycle, and this has been found to be the case for
the cLNGTM process also — especially in applications with high ambient temperatures.
The auxiliary refrigeration system is relatively small. Conventional chiller packages with
“ozone-friendly” Freon refrigerants are used rather than a propane system. This maintains
the safety philosophy for offshore applications.
2.4–8
By adding the cold expander, and by optimising the temperature levels and load split
between the warm and cold expander duties, a much closer matching of the heating and
cooling curves between the feed gas and nitrogen refrigerant can be obtained. This results
in higher thermodynamic efficiency. See Figures 5 and 6, which correspond to Cases 2 and
3 from Table 1 above.
The cumulative effect of these improvements is to reduce the specific power
requirements to a competitive level for small to medium LNG plant capacities, and yet to
retain all of the inherent safety and simplicity advantages of the simple nitrogen cycle.
50.0
NATURAL GAS
AND NITROGEN
COOLING
0.0
Temp [°C]
E1
-50.0
NITROGEN
REFRIGERANT
HEATING
-100.0
E2
-150.0
E3
-200.0
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
HEAT DUTY
Figure 5 - Simple Nitrogen Cycle Process: Heating / Cooling Curve
2.4–9
100.0
50.0
NATURAL GAS
AND NITROGEN
COOLING
Temp [°C]
0.0
E1
-50.0
NITROGEN
REFRIGERANT
HEATING
E2
-100.0
E3
-150.0
-200.0
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
100.0
HEAT DUTY
Figure 6 - cLNGTM Process: Heating / Cooling Curve
Description of cLNGTM Process for Bayu-Undan
A block flow diagram for the cLNGTM process as specifically designed for the BayuUndan gas resource is given as Figure 7. A single train of pretreatment removes acid
gases, water and mercury from the lean feed gas. Two independent trains of liquefaction
and refrigeration provide good overall availability and each train is capable of producing
up to 1.5 million tonnes per annum of LNG using a single gas turbine driver per train.
to
Fuel Gas System
Feed Gas
Reception
Feed Gas
Pretreatment
aMDEA
CO2 Wash
Feed Gas
Liquefaction
Cold Box /
Train 1
Nitrogen
Cycle
Refrigeration
Train1
Feed Gas
Liquefaction
Cold Box /
Train 2
Nitrogen
Cycle
Refrigeration
Train2
Feed Gas
Pretreatment
H2O and Hg
Removal
Fuel Gas
Compression
Cooling
System /
Train 1
Heating
System
Cooling
System /
Train 2
Fuel Gas
System
Electricity
Generation
System
Flare and
Blow Down
System
Instrument Air
and Utility
Air System
Nitrogen
Generation
System
Oily Water
System
Sweet Water
System
Figure 7 - Block Flow Diagram for Bayu-Undan cLNGTM Process
2.4–10
Fire Fighting
System
The lean feed gas is transported to the plant from the Bayu-Undan upstream facilities
by a high pressure pipeline operating at an inlet pressure of up to 180 bar. Because the gas
has already been processed to remove condensate and LPG in the field, the C5+ content of
the lean feed gas is very low. Gas can therefore be liquefied without reducing the gas
pressure for removal of C5+ hydrocarbons. Of course the recovery of make-up
hydrocarbon refrigerants, as is usually required for a mixed-refrigerant process, is not
required for the nitrogen cycle process. Thus the cLNGTM process can take full
thermodynamic advantage of the high feed gas pressure. The bulk of the feed gas is cooled
at a pressure of approx. 83 bar.
Figure 8 is a simplified process flow schematic for the liquefaction / refrigeration unit
for one train and illustrates the simplicity of the cLNGTM process. Feed gas enters the top
of the coil-wound heat exchanger and is cooled to approx. -90°C by nitrogen refrigerant
flowing on the shell side of a coil-wound-heat-exchanger (CWHE). A CWHE was chosen
for Bayu-Undan because of the high feed gas pressure, as well as the high reliability of this
type of exchanger. For lower feed gas pressures, brazed aluminium heat exchangers
installed in a cold box could also be used.
The cooled, high-pressure natural gas is then reduced in pressure and sub-cooled with
the coldest level of nitrogen refrigerant in two cores of brazed aluminium heat exchangers
installed in a cold box. A nitrogen stripper column and reboiler is required to reduce the
nitrogen content of the LNG product to less than 1 mol% because of the high nitrogen
content of the feed gas. For feeds with less nitrogen, a simple flash drum would be
adequate. Flash gas from the top of the nitrogen stripper column is warmed with nitrogen
refrigerant to recover the refrigeration potential of the stream and is then re-compressed to
fuel gas pressure.
The cLNGTM process maintains the simplicity of the nitrogen cycle used in LNG peakshaving units. Nitrogen refrigerant at a pressure of approx. 18 bar is compressed by a
single nitrogen compressor in two stages to approx. 50 bar. Seawater is used for intercooling and after-cooling. Both nitrogen compression stages are incorporated in a singlecase centrifugal compressor directly driven by an aero-derivative gas turbine. For BayuUndan, the large aero-derivatives such as the GE ‘LM-6000’ or Rolls Royce ‘Trent’ gas
turbines may be used to produce up to 1.5 mtpa of LNG per train. Inlet air cooling with a
chilled water system is used to maximise the power output of the gas turbines at the warm
ambient air temperature encountered at the Bayu-Undan site.
The use of inlet air cooling to maintain a nearly constant inlet temperature to the gas
turbine has an added benefit as the LNG production rate is nearly insensitive to daily and
seasonal variations in ambient air temperature. The majority of the process cooling is done
with seawater which only varies over a small temperature range at this location.
2.4–11
C oo ling
T reated N atu ra l G a s
G as Tu rb in e
C ycle
C om p resso r
C hillin g
C oo ling
T o Fuel
Fuel Ga s
C o m p resso r
W a rm
E xpan der/B o o ster
N itro g en
S trip
C o lu m n
C old E xpan d er/B oo ster
C o ld
B ox
LN G S torage
LN G T rans fe r Pu m p
Tank
Figure 8 - Process Schematic for Bayu-Undan cLNGTM Process
The nitrogen refrigerant is further compressed to approx. 84 bar by the booster
compressors of the warm and cold expander / booster units. The high pressure nitrogen is
then cooled with seawater and chilled water to approx. 10°C. The chilled water system is
comprised of electrically driven Freon refrigeration units and supplies chilled water for
cooling of the high pressure nitrogen, treated feed gas and inlet air to the gas turbines.
Cooled high pressure nitrogen then flows to the nitrogen tube pass of the main CWHE
where it is pre-cooled with low pressure nitrogen to approx. -15°C in the first tube bundle.
This cold nitrogen stream is then split into two portions and the larger portion flows to the
warm expander / booster units where it is expanded to low pressure and temperature. This
cold nitrogen stream flows to the shell-side of the main CWHE to provide the bulk of the
cooling of the natural gas and high pressure nitrogen refrigerant.
The smaller portion of cooled high pressure nitrogen is then further cooled in the
nitrogen tube pass of the main CWHE to approx. -90°C in the second tube bundle. This
cold high pressure nitrogen stream then flows to the cold expander/booster unit where it is
expanded to low pressure and a temperature of approx. -150°C which provides the subcooling of the natural gas in the brazed aluminium cores in the cold box. The nitrogen
leaving the cold box joins the larger nitrogen steam coming from the discharge of the
warm expander / booster units and flows to the shell side of the main CWHE.
The machines used for both the warm and cold expander/booster units for this train
size are large, but are still within proven experience ranges for the manufacturers.
2.4–12
Gas Conversion Efficiency of cLNGTMProcess for Bayu-Undan
The gas conversion efficiency (heating value of the LNG product to storage divided by
the heating value of the feed gas) of the above process is 92 - 93%. This result is very
satisfactory given that the specific power requirements of the process are still approx. 25%
higher than a typical onshore base-load plant.
The reason for this high conversion efficiency can be explained by the relatively high
fuel efficiency of the aero-derivative gas turbines used for the main drivers. The efficiency
of turbines such as the Rolls Royce ‘Trent’ or GE ‘LM6000’ is significantly higher than
the efficiency of the industrial type gas turbines presently used in onshore LNG plants.
cLNGTM PROCESS MODULE
A 3-D computer aided drawing of the cLNGTM Process Module for Bayu-Undan is
given as Figure 9. Included on the module is the equipment comprising a single train of
gas pretreatment (acid gas removal and dehydration), two trains of liquefaction, electricity
generation and other utilities. Studies show that process facilities for the production of
two to three mtpa of LNG per year can be fabricated in a single process module that
weighs approx. 10,000 tonnes. Such a module is similar in size to other offshore modules
that have been constructed in a number of fabrication yards around the world.
The module is loaded out from the fabrication yard onto a heavy lift barge on multiwheeled trailers, such as has been done for other modules of similar size. The process
module can then be transported to the GBS for installation using the same multi-wheeled
trailers used for the load-out. The module is never lifted and is always supported at a
number of points. As a result, the amount of structural steel required is much less than on
some other large offshore modules. One advantage of this method of construction is that
extensive pre-commissioning and testing can be carried out on the completed process
module in the fabrication yard, in order to minimise offshore hook-up and installation.
Cold Boxes
Spiral-Wound
Heat Exch.
Gas
Treating
Figure 9 - cLNGTM Process Module
2.4–13
Gas Turbines
cLNGTM RELIABILITY EXPECTED TO BE SIMILAR TO OTHER
FACILITIES
The LNG industry demands a high level of supply reliability, and actual reliability
performance of existing plants and design methods have been documented [9,10,11,12].
The cLNGTM processing plant as designed for Bayu-Undan has been the subject of a
detailed Reliability, Availability, and Maintainability (RAM) study, using state-of-the-art
computer tools and equipment reliability databases. An average availability of over 96% is
expected for the cLNGTM processing plant itself. This is on par with world-class LNG
plants in operation today.
Features of the cLNGTM process that contribute to its high reliability include:
•
•
•
•
•
•
•
•
the relative simplicity of the pretreatment process required for the lean gas
produced from Bayu-Undan,
the relative simplicity of the nitrogen cycle liquefaction process, which requires only
one main driver,
the provision of dual (2 x 50%) liquefaction trains,
the inherent ability of the cLNGTM process to maintain LNG production, albeit at
reduced capacity, while parts of the nitrogen cycle are shutdown,
the selection of proven equipment provided by vendors with established references,
the rapid maintenance turnarounds possible with aero-derivative gas turbines,
the provision of adequate design margins,
the provision of redundant equipment, such as spare pumps, heat exchangers,
power generation facilities, utility equipment, etc.
2.4–14
CONVENTIONAL CONCRETE GRAVITY BASE STRUCTURE
SUPPORTS LNG PLANT, TOPSIDES FACILITIES AND STORAGE
TANKS
The cLNGTM facility proposed for Bayu-Undan is shown in Figures 1 and 3 in a typical
configuration for two to three mtpa LNG production. The cLNGTM process module is
shown centred between the two LNG storage tanks. The personnel accommodation
module is safely positioned at one end, away from the process, flare, incoming gas riser,
and loading terminal. The entire facility is supported on a concrete gravity base structure
(GBS) which rests directly on the seabed in relatively shallow water (~27 m). Concrete
GBS’s have been used for many years in the North Sea and at far greater depths ranging
up to 300 meters. More recently, three GBS based production facilities have been installed
in Australian waters, two in the Bass Strait (West Tuna and Bream B) and one on the
North West Shelf (Wandoo).
The GBS required to support the cLNGTM facilities is relatively simple in design and
construction terms, and is heavily based on proven offshore technology. Figure 10 shows a
cutaway sketch of the GBS supporting structure. The simple rectangular cell arrangement
is evident. The wave protection wall with wave deflector lip extends above the top slab to
deflect extreme waves away from the topsides equipment during the cyclonic storms. The
prestressed concrete LNG tanks are constructed on the top slab, which also incorporates
the embedment plates as foundations for the other modularised topsides equipment.
At the seabed level, there is an extra buoyancy structure, or “cantilever”. This is added
to provide the buoyancy necessary to allow the GBS structure, complete with all precommissioned topsides equipment, including the LNG tanks, to float out of the casting
basin in which it is constructed. Once out of the casting basin and in deeper water, the
cantilever is flooded, and the GBS is towed to the offshore site at deeper draught. At the
correct location, and in the correct orientation, the GBS is gently flooded down to the
seabed. Every cell is flooded, and many cells are then partly filled with iron ore ballast, to
ensure adequate weight on the seabed for wave resistance.
Like all offshore structures, the GBS configuration and detail design is heavily
dependent on site specific conditions and the construction method. The structure shown,
and the figures listed in Table 2, reflect the Bayu-Undan design. The basis of design data,
such as metocean conditions, geotechnical conditions at the proposed site, seismic criteria,
etc., have been gathered for this project. The particularly critical design input parameters
which govern the overall configuration for such a GBS application are:
•
•
•
•
water depth and tidal range at the offshore location;
geotechnical conditions at the offshore location;
casting basin and tow-out channel water depths;
topsides size and weight for float out and tow to the offshore location.
2.4–15
Figure 10 - GBS Cutaway View
Some design parameters have greater sensitivity for this offshore LNG GBS
application, and these were carefully considered for Bayu-Undan. For example, the large
topsides weight of nearly 200,000 tonnes (when the LNG tanks are full), must be
accommodated. The topsides weight will vary during operation as the LNG tanks are
repeatedly filled and emptied. However, the loads during LNG tank hydrotesting may
govern the design. The potential for LNG to “slosh” inside the tanks, because of very
small movements of the GBS during extreme storms waves, must be considered. As LNG
tank construction is critical path, early access to the GBS is required. Fendering and
mooring points must be provided for the integral loading terminal. The geometry and
strength of these must be suitable to berth standard LNG Carriers with standard
equipment. Room is provided on the GBS for future expansion via an additional LNG
train, since the GBS offers great capability to support additional topsides equipment.
Finally, abandonment of the GBS must be considered: the facility may be removed and
possibly re-used at the end of the project life.
Table 2 - Key Dimensions for the Bayu-Undan GBS Substructure.
Length - at seabed, at waterline
Width - at seabed, at waterline
Height - seabed to top slab
Typical Cell Size
Concrete Volume
Steel Reinforcement
Prestressing Reinforcement
Solid Ballast (iron ore)
Top and Bottom Slab Thickness
Wall Thickness (varies)
274m, 249m
111m, 86m
35m
12 x 12 m
100,000 m3
27,700 tonnes
3,700 tonnes
350,000 tonnes
600 to 900 mm
400 to 600 mm
2.4–16
LNG STORAGE TANKS AND OFFLOADING TERMINAL ARE STATEOF-THE-ART
The LNG tanks selected are of the latest design and highest integrity “land-based” type
full containment tanks as used for the most recent Japanese tank constructions. They
consist of a 9% nickel-steel inner tank and a 800 mm thick pre-stressed concrete outer
tank, with a domed, reinforced concrete roof.
These tanks simply sit on the GBS top concrete slab, which is at all times above the
waterline. A concrete outer wall was selected based on safety considerations in order to
give unsurpassed protection from potential external events such as dropped objects and
blast over-pressures. For Bayu-Undan, the storage volume selected is 170,000 m3 total, in
two equal-sized tanks. The outer concrete tank diameter is 66m, the inner steel tank
diameter is 62m, and the wall height is 34m.
Offloading of LNG from the storage tanks to standard LNG Carriers takes place at the
terminal integral to the GBS. This incorporates a steel platform which supports the
loading arms at the correct height, a fendering system attached to the side of the GBS, and
mooring platforms with quick release hooks and capstan winches. All this equipment is
standard and proven, albeit the latest available, with the best automatic type facilities for
good operability and safety performance.
Four, 400 mm (16”) diameter loading arms are provided, with a total loading capacity
of 10,000 m3/hour. These are standard arms, as supplied by either FMC or Niigata, and
incorporate the hydraulic control package, emergency shutdown system, a double-ballvalve powered-emergency-release-coupling, a quick connect / disconnect coupler, and a
position monitoring system. The operating envelope is selected to exceed the relative
motions expected to be seen at the Carrier manifold.
The five main berthing fenders are Yokohama Air Block type, with soft energy
absorption characteristics, and long stroke to allow Carrier berth velocities of up to 0.3
knots These have been used at similar exposed location terminals for similar applications.
The mooring system developed for operating the LNG Carriers (125,000 m3 or larger)
at the GBS terminal is fully in accordance with the universally adopted Oil Companies
International Marine Forum (OCIMF) guidelines. The arrangement is similar to that used
for ship-to-ship loading. The breasting lines are almost perpendicular to the Carrier axis,
providing extra stiffness for firm lateral control of ship movement.
RELIABLE LNG CARRIER LOADING AT THE INTEGRAL GBS
TERMINAL
Reliable LNG Carrier loading, with availability equivalent to inshore terminals, is a
pre-requisite for an offshore LNG facility. As mentioned above, the technology required to
reliably load LNG Carriers from a floating LNG plant is still under study and requires
development. However, the static GBS based LNG plant allows conventional type LNG
loading systems to be used. In order to confirm this for Bayu-Undan, a comprehensive
series of model tests and simulations have been completed. These were done at MARIN
2.4–17
for the moored condition, and at MSCN and the Australian Maritime College (AMC) for
the berthing procedures and limits. Additionally, advice was sought from experienced
LNG Carrier Masters and Operators to conclude with workable solutions and equipment.
Initial computer based mooring simulations and fast-time berthing studies concluded
that in order to achieve high availability, it would be necessary to berth and remain
moored at higher seastates than normal for inshore terminals. It was also concluded that a
standard LNG Carrier could not berth at the GBS in these seastates without external
assistance from tugs or thrusters. Once moored, the mooring system would need to be
more robust than the moorings used at inshore terminals. These studies proposed that a
seastate of Hs = 2.6m was a practical limit for the moored condition, and that this was
compatible with tug handling limits for the berthing procedures.
The physical model testing performed at MARIN aimed to confirm the computer
results and to assess the availability of the LNG Carrier whilst moored at the berth. A
whole series of tests were performed with different wave heights and directions simulated,
together with wind and current effects. See Figure 11.
The GBS orientation was altered, and Carrier motions, mooring line tensions and
fender loads measured and recorded. A number of conclusions were reached:
• the GBS should be oriented east-west at Bayu-Undan for maximum moored
availability;
• fender loads and motions were not exceeded, and therefore did not govern;
• loading manifold motions were within the capability of existing loading arms;
• the mooring line loads would govern the availability while moored.
Figure 11 - Wave Tank Test of LNG Carrier Mooring
To assess the berthing limit and the availability of berthing, the complete Carrier
approach and mooring-up procedure was simulated. MSCN performed fast-time computer
simulations. These were checked by real-time simulations performed at AMC, attended by
2.4–18
an experienced LNG Carrier Master and experienced pilots. A view of the full-scale LNG
Carrier bridge at AMC and simulated GBS is given as Figure 12.
Figure 12 - Virtual Reality Simulation of Carrier
Berthing at the GBS Based cLNGTM Plant
A number of simulations were run under a variety of extreme operating conditions.
The results were very positive, finding favour and acceptance from the Mariners, and two
main conclusions were made. The seastate of Hs 2.6m was confirmed to be the upper limit
for the tugs and Carrier. If the Carrier is fitted with bow thrusters and a high lift rudder,
no tugs are required. Two tugs would be needed if the Carrier were not so outfitted.
Based on the results of the model tests and simulations, Marin performed an overall
real time downtime analysis based on realistic seastates. This effectively takes true account
of the time the LNG Carriers are at the berth, and accounts for each and every part of the
berthing, mooring, loading, unmooring, and departing procedures. The results of this work
for Bayu-Undan show that a 98% availability for the LNG Carrier loading operations at
the integral GBS berth is achievable.
SAFETY AND DESIGN APPRAISAL
The results of a Quantitative Risk Analysis (QRA) show that the risk to workers at the
GBS based cLNGTM facility is lower than industry guidelines and comparable to other
offshore operations. Features that reduce risk include:
•
•
•
•
the selection of inert nitrogen gas as the refrigerant,
the supply of only lean gas to the facility, thereby eliminating the need for
handling LPG’s or heavy hydrocarbons anywhere on the GBS,
the selection of full-containment prestressed-concrete LNG storage tanks,
the provision of a relatively un-congested cLNGTM process module which limits
explosion overpressures,
2.4–19
•
•
the selection of the safest locations for the accommodation module and other
ancillary equipment on the GBS,
extensive use of safety systems such as gas detection and fire-protection.
State-of-the-art tools such as computational fluid dynamics (CFD) and threedimensional gas dispersion and explosion modelling have been used to predict the impact
of gas and LNG releases. When compared to another LNG facility that may use mixed
hydrocarbon refrigerants (containing heavy LPG components) or a heavy feed gas, the
advantages of using nitrogen, which is inert, and feed gas that is predominantly methane,
are clear. Methane’s physical properties are more favourable than heavier hydrocarbons,
with respect to dispersion, flammability in air, and the potential explosion over-pressures
that could result from an ignited gas cloud.
One design constraint was that the LNG storage tanks should be able to withstand the
maximum credible explosion over-pressures caused by large gas releases from the process
module or LNG loading area. From extensive CFD, explosion, and structural analysis, this
has been confirmed. Furthermore, the essentially inanimate LNG storage tanks can then
act as a blast wall to protect the personnel accommodation module, which houses the
control room, recreation and sleeping quarters, and so forth. Modelling has shown that the
over-pressures that extend around the storage tank to the accommodation module are
insufficient to cause structural damage or loss of life.
Some of the results of the QRA are given in Figure 13. This shows that the Individual
Risk Per Annum (IRPA) for each worker group (production worker, support staff, etc.) is
within acceptable industry limits and comparable with other offshore facilities. The risk
levels fall within the “as low as reasonably practicable” (ALARP) region, where further
risk reduction measures will be considered during the course of project development.
Further studies will be conducted in accordance with the Safety Case development in
order to show that risk has been reduced to as low as reasonably practicable. As is
commonly seen for remote offshore operations, a breakdown of the contributors to
personnel risk highlights the risks associated with transporting workers to the facility via
helicopter and transferring the mooring master to the shuttling LNG carriers (if this
position is in fact required). The QRA results show that the risks to personnel of
helicopter operations probably exceed any special risks associated with LNG processing.
2.4–20
BHP / INDUSTRY
MAXIMUM
ACCEPTABLE RISK
LIMIT
(> 1 E-03)
RISK AREAS
WORKER
GROUPS
OCCUPATIONAL
HAZARDS
TRANSFER OF
MOORING MASTER TO
LNG CARRIER
HELICOPTER
OPERATIONS
VESSEL IMPACT
OTHER PROCESS
LNG
PROCESS
MANAGEMENT
SUPPORT
STAFF
MAINTENANCE
WORKER
PRODUCTION
WORKER
MARINE
LOGISTICS
MOORING
MASTER
Figure 13 - QRA Results: Individual Risk Per Annum (IRPA)
The feasibility design documents for the Bayu-Undan Offshore LNG Facility have been
appraised in accordance with Det Norske Veritas’ (DNV) rules for Classification of Fixed
Offshore Installations for technical progress relative to the current (feasibility design)
milestone of the project and for the use of applicable rules and regulations.
As a result of this review of the key areas of the design, DNV confirm that technical
development of the project has been satisfactorily achieved for this milestone, and that
there is no impediment to continuing the process to achieve Certification. Furthermore,
there are no areas requiring significant new research and development in order to achieve
a safely operable facility within the normal time frame and quality standards of major
offshore and LNG projects. This assessment reflects the extensive amount of work carried
during this extended feasibility stage.
CONCLUSION
A feasible and economic means to produce and export LNG from remote marginal gas
fields has been developed, using cLNGTM technology. The design cost effectively utilises
proven technology elements brought together specifically by the need to commercialise
remote gas resources. Detailed model testing, and safety and reliability studies confirm the
safe and reliable operation of all aspects of the LNG facility. Detailed cost estimates
confirm that LNG production from an offshore facility in the range of two to three million
tonnes per year is competitive with larger land-based LNG facilities on a cost per tonne of
LNG basis. The cLNGTM process is ready to use for LNG base-load applications in order
to commercialise remote marginal gas fields.
2.4–21
ACKNOWLEDGMENTS
The authors, BHP, and Linde AG would like to recognise the contributions of other
groups involved in the development of this facility including Aker Maritime, Fluor Daniel,
Clough Offshore, John Holland, the Australian Institute of Marine Science, the Australian
Maritime College, Det Norske Veritas, IHI, Jardine and Associates, Marin, MSCN,
Obayashi, Osaka Gas, and many others.
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3.
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4.
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2.4–22