Emerging Technology Allows Greater Flexibility for the Design and
Operation of FLNGs
By
Peter J H Carnell
Kevin Robinson
Vince A Row
Abstract
Conventional LNG plants are built to process gas from a defined gas field to
produce LNG for a specific customer. Space is not a constraint and there are
no operational limits on the type of technology that is employed. In contrast
Floating Liquefied Natural Gas (FLNG) units will have to offer much greater
flexibility. They are likely to be used on small fields and may have to be
relocated during their working life and supply LNG to different markets. There
is limited capacity for storage of co-produced Natural Gas Liquids (NGL) and
export of different product streams complicates trans-shipment. Conventional
acid gas removal units (AGRU) pose a problem off shore as they require tall
structures, need level operation and require operator monitoring.
The design and operation can be greatly simplified by switching to the use of
fixed bed technology. Thus the integration of membranes with fixed bed
absorbents for mercury and H2S removal simplifies the AGRU. Similarly the
use of catalytic derichment (CDR) allows the conversion of NGLs to methane
so that only LNG needs to be stored on the platform.
Adoption of these processes simplifies the design of the unit and allows
greater flexibility in the markets available and the gas fields that can be
worked.
Introduction
Most LNG plants have been constructed to provide gas to meet a specific
regional gas market. In its simplest form the LNG tanker has replaced a gas
pipeline connecting the gas processing plant with the market. The LNG is
produced to match the combustion specifications for a specific market. The
burgeoning LNG market means that “spot” sales for LNG are now possible but
this is complicated by the regional differences in the domestic gas markets.
The two parameters of most concern are the Higher Heating Value (HHV) and
the Wobbe Index. Regional differences in the requirement for HHV and
Wobbe Index are shown in Figure 1[1]
For spot sales, the producers rely on the receiving terminal making the
changes in Wobbe Number and Higher Heating Value (HHV) needed to meet
local requirements. They also have adequate storage or a local use to take
care of the co-produced higher hydrocarbons that cannot be blended with the
product LNG.
HHV(MJ/sm3)
Figure 1 Worldwide Heating Value Specifications
46
12
11
45
44
10
9
43
8
42
41
7
6
40
39
5
38
4
37
3
36
2
35
1
34
0
Japan
Korea
USA
UK
France
Spain
Raising the HHV can usually be achieved by the addition of LPG. Lowering
the HHV is more complex in that either NGLs must be removed or an inert gas
like nitrogen must be added. Studies in the UK have shown that rich LNGs
(Nigeria and Indonesia) would require 85% of the gas to be processed for
ethane removal to meet the sales specification and there would be a flow
reduction of 10%.
Nitrogen ballasting is not without complications. The scale of usage means
that the nitrogen must be available as liquid and this adds the requirement of
access to a liquefaction plant. In general it is easier to raise the HHV than to
lower it. In many ways it offers more marketing flexibility for the LNG producer
to produce low HHV LNG.
Raw gas compositions can vary widely and although the acid gas removal unit
(AGRU) can be designed to manage variations in CO2 and H2S, disposal of
NGLs is harder to control. Most LNG plants are in remote locations with little
immediate use for NGLs. LPG is marketable but ethane is more of a problem.
Vapour pressure limits restrict the ethane content of LPG to around 2%.
The UK and Californian specifications limit the ethane to 6% of LNG and if the
raw gas contains more than 8-9% ethane then the ethane must either be used
within the plant or exported. As a general rule an LNG plant uses around 10%
of the raw gas as fuel. If the raw gas contains 9% ethane then the resulting
fuel gas will contain 36% ethane and will be too rich to meet the NOx emission
limits of the larger gas turbines.
Different design criteria have to be applied to FLNG designs. These will be
smaller units. They may have to be relocated to a different field and serve a
different market during their working life. Storage space is limited.
The world’s first LNG floating production storage and offloading vessels are
now under construction in Korea. These would have storage for 170,000 m 3
LNG and 50,000 m3 condensate. The optimum size of storage in FNLG
designs being considered at the moment is governed by the logistics of
providing a full load for the transhipping tanker and co-ordination of the
transfer operation.
Thus one design based on using a Qmax LNG vessel would have storage for
350,000 m3 LNG, 80,000 m3 LPG and 160,000 m3 of condensate and if the
raw gas had a high ethane content excess would have to be used as fuel or
flared [2].
Ship to ship transfers (STS) involve complex operations and require an
acceptable sea state. The complexity is illustrated by the recently published
time log for an STS transfer between Exmar NV and Excelerate [3]. The
transfer of LNG was at 5000 m3/hr and took 25 hrs but the whole operation
took 45 hrs. The STS time log is shown in Table 1
Table 1: STS Transfer Time Log
Operation
Duration (hrs)
Rigging fenders
1.0
Approach Manoeuvre
1.9
Mooring
1.9
Pre-transfer safety meeting
1.0
Connecting hoses
2.5
Hose purge and cool-down
4.0
Emergency shutdown test
0.7
Cargo transfer
25.8
Hose drain and purge
2.0
Disconnect hoses
2.0
Letting go mooring lines
0.9
Separate vessels
0.3
Recover fenders
1.0
Total duration of STS transfer
45.0
Transfer of LPG and condensates is less complicated but still adds additional
worries to the operator to ensure safe docking and transfer.
Johnson Matthey has recognised these problems and has developed catalytic
de-richment (CDR) to simplify FLNG design and operation. The process is
derived from technology already in use for substitute natural gas production
(SNG).
The process involves the following stages. The unwanted higher
hydrocarbons, which can be from ethane to naphtha, are desulphurised and
then reacted with steam to give a gas stream containing carbon oxides and
hydrogen. This is passed to a methanator to produce a mixture of methane
and carbon dioxide which is returned to the front end of the LNG unit.
The reactors are relatively small and operation is fully automatic.
Adoption of this technology will allow “lean” LNG to be produced which
increases flexibility in sales, as it is easier for the receiving terminal to add
LPG to raise the HHV than to add nitrogen to lower the HHV. Storage space is
freed up for LNG and flaring could well be reduced.
Catalytic De-richment (CDR)
This is a development of a process to convert the higher hydrocarbons into
substitute natural gas (SNG). This was developed by British Gas in 1968 and
is sold under licence by Davy Process Technology using Johnson Matthey
catalysts. This process was developed to allow the manufacture of pipeline
gas from naphtha but is even better suited for the conversion of low molecular
weight hydrocarbons to methane [4] & [5]
The process starts with the steam reforming of the hydrocarbon to give
hydrogen and carbon monoxide which coupled with the shift reaction gives
hydrogen and carbon dioxide. Hydrogen is then reacted with carbon monoxide
to give methane and water.
The overall reactions for ethane, propane, butane and pentane are:
4C2H6 + 9H2O  7CH4 + 7H2O + CO2
2C3H8 + 7H2O  5CH4 + 5H2O + CO2
4C4H10 + 19H2O  13CH4 + 13H2O + 3CO2
C5H12 + 6H2O  4CH4 + 4H2O +CO2
Simplified process flow diagrams are shown in Figures 2 & 3. Ethane is the
most efficient hydrocarbon for methane conversion with a reforming
temperature of 300 to 350°C. Not only does the process allow for the derichment of LNG but also increases the methane yield.
The operation of a plant supplied with a CDR conversion unit has
considerable flexibility. Thus the quality of the LNG produced can be adjusted
by tuning the fraction of the de-ethaniser overhead stream sent for conversion
and, given segregated storage tanks, can supply different markets.
Figure 2: Location of CDR Unit in Liquefaction Plant
Figure 3:Simplified CDR Flowsheet
The above flow sheet shows the essential components of the CDR process.
The product gas can be returned to the feed to the acid gas removal plant.
The potential increase in LNG production obtained from say 100 mmscfd of
raw gas with different gas compositions is shown in Table 2.
Table 2: Potential Increase in LNG production from Heavy Gases Using
CDR.
Raw Gas Composition
Methane
(mmscfd)
100
95
90
85
Ethane
(mmscfd)
5
5
10
Propane
(mmscfd)
3
5
Product Gas Composition
Butane
(mmscfd)
2
-
Methane
(mmscfd)
100
104
113
115
Increase in
methane (%)
9
26
35
Raw Gas Purification
The raw gas is likely to contain CO2, H2S and mercury. All of these
compounds must be removed prior to liquefaction and again it is worth
considering the most appropriate design for an FLNG unit.
Dealing with Mercury Issues
Almost all hydrocarbons contain mercury. In the case of natural gas and
natural gas liquids it is likely to be present as elemental mercury.
The concentration of mercury in natural gas varies widely from 450 to 5000
μg/Nm3 in some fields in North Germany to less than 0.01 μg/Nm3 in some
parts of the US and Africa. Reported levels of mercury found in some well
known gas fields are given in Table 3.
Table 3: Reported Levels of Mercury in Specific Gas Fields.
Gas Field
Groningen
Arun
Albatross & Askeland
Niger Delta
North & East Coast Trinidad
Goodwin, N Rankin & Perseus
Saih Nihayda & Saih Rawl
Amount (μg/Nm3)
180 - 200
250 - 300
1.0
10
12
38
60
Mercury has a high boiling point (356.7 °C) but has a high vapour pressure at
ambient temperature and is surprisingly mobile.
Although the levels of mercury recorded are low, the tonnages of
hydrocarbons handled are enormous so downstream processing equipment is
exposed to a substantial amount of mercury. Thus one FLNG being
considered [2] would produce 5 mtpa LNG from 600 mmscfd of natural gas
and if this contained 100 µg/m3 mercury the plant would receive 582 kg
mercury per year.
The main concerns are corrosion of process equipment and health and safety
issues. These can cause serious financial losses for the plant operator. Two
major types of mercury-corrosion can be observed. These are amalgam
corrosion and liquid metal embrittlement (LME). Amalgam induced corrosion
is shown by any metal capable of forming an amalgam with mercury. Most
metals owe protection from corrosion to the presence of an oxide layer. If this
protective layer is damaged in the presence of liquid mercury, then the metal
can show its full reactivity and attack by air or water is rapid.
LME involves the diffusion of mercury into the grain boundaries and results in
cracks developing along the grain boundary. This type of attack does not
involve air or water and once initiated progresses rapidly and can result in
catastrophic failure.
All LNG plants have mercury removal units (MRU) but these are normally
installed immediately after the molecular sieve dryers to protect sensitive
cryogenic equipment.
However, this ignores the problem of mercury emissions from the AGRU and
dryer regeneration vents, the presence of mercury in NGLs and the
contamination of process equipment. Many operators are setting a limit on the
level of mercury in LPG and naphtha for use on petrochemical plants. Plant
surveys have shown that around half of the mercury present in the raw gas is
lost through vents or in NGLs.
Hence there is a strong case for installing the MRU at the front of the plant to
treat the raw gas and thus avoid both damage to equipment and emission of
mercury to the environment [6].
This can easily be achieved by the installation of a fixed bed absorbent at the
front end of the plant.
Acid Gas Removal
A conventional shore based LNG plant will use some form of wash process for
the bulk removal of CO2 and H2S. This will require two tall towers, one for the
absorber and the other for the stripper. These towers are massive structures
with considerable wind resistance that require to be kept nearly vertical to
keep the liquid on the trays level. They are used on off shore platforms but for
these reasons are less popular for “floaters”
Wash processes have a high energy demand for regeneration and so are not
viable for dealing with levels of CO2 much above 20%. The viability of the
different processes is shown in Figure 4.[7]
Figure 4: Effect of CO2 Concentration in Raw Gas on the Viability of CO2
Removal Processes.
In contrast semi-permeable membranes have a number of advantages over
wash processes. There are no high structures, they can handle gases with a
high CO2 content, there are no circulating liquids and they can have a drying
role. However, the current generation of membranes suffer from being easily
damaged and having poor selectivity. The membranes favour the passage
polar compounds such as CO2, H2S and H2O over hydrocarbons but the
relative rates of diffusion cannot be controlled. Thus if the H2S/CO2 ratio is too
high too much CO2 will have to be removed to meet the H2S specification.
This problem can be avoided by the utilisation of a fixed bed absorbent for the
removal of H2S alone. This arrangement is already being used by Boral
Energy in Western Australia
Conclusion
The production of LNG on floating platforms poses a number of technical and
logistical problems. Most of the emphasis to date has been to install a
conventional land based design on a suitable vessel. The use of a more
innovative approach could greatly simplify the design and operation of the
plant. Catalytic De-Richment can be used to increase LNG production free up
space for LNG storage and reduce the need for flaring.
References
1) Coyle. D., de la Vega. F. F. and Durr. C., “Natural Gas Specification
Challenges in the LNG Industry” 15th International Conference &
Exhibition on Liquefied Natural Gas (LNG15), Barcelona, Spain 24th –
27th April, 2007
2) Wilkes.M., and Anderson. K., “Floating LNG Liquefaction Using the
Optimized CascadeSM Process” Gas Processors Association-Europe,
Technical Conference, Ashford, Kent, UK, May 14th to 16th 2008
3) Offshore LNG Supplement Nov/Dec 2008 “STS transfers optimise
regas vessel logistics” p10 –14.
4) Yang. C. C., Bothamley. G., “Maximising the Value of Surplus Ethane
and Cost-Effective Design to Handle Rich LNG” 15th International
Conference & Exhibition on Liquefied Natural Gas (LNG15), Barcelona,
Spain 24th –27th April, 2007
5) Chrétien. D.,”Process for the Adjustment of the HHV in the LNG
Plants”, 23rd World Gas Conference, June 2006. Patent Application
GB 2432369.
6) Carnell. P., McKenna. R and Row. V. “A Re-think of the Mercury
Removal problem for LNG Plants” LNG15 Barcelona, April 24th to 26th
2007.
7) Baker. R.W. and Lokhandawala. K. “Natural Gas Processing with
Membranes: An Overview” Ind. Eng. Chem.2008,47,2109-2121.