88th Annual Convention, March 8-11, 2009
Gas Processors Association
Design, Fabrication and Startup of an Offshore Membrane CO2
Removal System
William Echt
and
Peter Meister
UOP LLC, A Honeywell Company
Des Plaines, Illinois, USA
© 2009 UOP LLC All Rights Reserved
ABSTRACT
As the world searches for more energy in more remote locations, natural gas reserves that
would have been marginal or unprofitable years ago are now being developed. Many of
these reserves are offshore and contain large amounts of carbon dioxide. Pipelines and
compression to bring the gas to shore are expensive, so at least partial offshore gas
conditioning makes economic sense.
This paper presents the results of a project to bring offshore natural gas reserves into
production for delivery in Asia. The design of the UOP Separex™ membrane system for
CO2 removal is reviewed, showing key considerations that impact the project economics.
Of particular interest are the integration of the mercury removal and natural gas liquids
(NGL) recovery systems with the CO2 removal system and the comparison of the chosen
pretreatment design to an alternate scheme that uses chilling for pretreatment. The
method of constructing the offshore platform is also presented and important fabrication
steps are highlighted. Finally, a review of the platform startup is presented with initial
and current operating data.
UOP worked closely with our customer in all phases of the project. The optimized
design has proven to meet performance expectations. The UOP system is operating since
March 2007 without significant membrane replacement.
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88th Annual Convention, March 8-11, 2009
Gas Processors Association
Introduction
In the summer of 2002, UOP was approached to provide budgetary membrane system
design for CO2 removal to be installed on an offshore gas processing platform in Asian
waters. Following comprehensive engineering and cost evaluation, UOP was awarded
the supply of a UOP MemGuard™ pretreatment system and downstream Separex
membrane system in the fall of 2003. The platform was completed in the fabrication yard
in the winter of 2005 and gas first entered the facility in spring 2007.
This paper presents the results and lessons-learned from design, fabrication, installation
and start-up of this large offshore facility. As the supplier of the key process technology
for the new platform, UOP was involved in all phases of the project. This paper
highlights and discusses design features that are of general interest as well as those
specific to the Separex membrane unit for CO2 removal.
Project Definition
Armed with reservoir information from existing producing wells and the results of initial
choke flows from newly drilled wells, the production company established a plan to
install additional oil and gas processing capacity. Fields adjacent to existing offshore
facilities contained significant oil reserves, but the associated gas had CO2 levels ranging
from 26 to 55%. By blending producing oil wells with lower-CO2 gas wells, it was
calculated that feed gas to the new processing platform could be maintained at a
maximum 44.5% CO2. Export gas from the platform had to be dehydrated and meet a
pipeline specification of 8% CO2. The export gas capacity was required to be 320
MMSCFD minimum, with a design capacity of 350 MMSCFD, which translates to a feed
gas flow rate of 590-680 MMSCFD, depending upon the actual CO2 content in the feed
gas and the mode of operation of the membrane unit. Feed gas definition and key
product gas specifications are shown in Tables 1 and 2, respectively.
Table 1 – Feed Gas Definition
Flow (MMSCFD) Maximum
Pressure (kPag)
Temperature (°C)
Composition
680.0
4000
47
mole %
Carbon Dioxide
Methane
Ethane
Propane
C4+
Nitrogen
Water
Mercury
44.49
46.63
4.18
1.94
2.76
0.84
Saturated
40 µg/Sm3
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88th Annual Convention, March 8-11, 2009
Gas Processors Association
Table 2 – Product Gas Specification
Flow (MMSCFD) Minimum
320
Composition Specifications
Carbon Dioxide
Water
Mercury
< 8.00 mole%
<5 lb/MMSCF
<5 µg/Sm3
Process Scheme Selection
In conjunction with an engineering company retained to design platforms and prepare
cost estimates, the producer performed front end engineering design work on several
process scheme alternatives.
The evaluations were based on a fundamental decision to integrate the process equipment
into the platform decks. This construction method differs from the modular method
whereby all the equipment is first installed on steel frames, piped to the edge of the
module and where the pre-fabricated modules are then pieced together on platform jacket
supports. Integrated platform construction is generally considered to have less structural
steel and less overall weight compared to modular installations.
Each process scheme alternative was evaluated in terms of process performance, cost,
plot space and weight and even included the optimization of the supporting platform
jacket design for each process scheme.
Integration of NGL Recovery with CO2 Removal
In particular, the location of NGL recovery equipment either upstream or downstream of
the CO2 removal unit was examined. Condensed NGL were to be stabilized and mixed
with produced oil to increase revenue. The location of NGL recovery within the gas
processing scheme was a critical design parameter that impacted platform size, weight
and cost. Figures 1 and 2 show the block flow diagrams for two key process schemes
that were most closely compared.
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88th Annual Convention, March 8-11, 2009
Gas Processors Association
Figure 1 – Cold System
Feed
(Future)
Feed
Compression
and Cooling
Dehydration
Mercury
Removal
And
Pretreatment
Permeate
Export
Membrane
Separation
Export
Compression
and Cooling
Downstream
Chilling /
NGL
Recovery
Compressed
Overhead
Vapors
NGL
NGL
Stabilization
Figure 2 – Warm System
The “Cold System” requires upstream dehydration as the feed gas will be chilled below
the hydrate formation temperature. After mercury removal, the gas is chilled to
accomplish two objectives: (a) NGL recovery and (b) removal of heavy hydrocarbons
and aromatic compounds that, when condensed into liquids, damage the downstream
membrane elements. Downstream of chilling, membranes remove the CO2 to
specification. Because of the very low operating temperature, light hydrocarbon liquids
are condensed on the membrane surface. All hydrocarbon liquids are routed to the
stabilizer and the overhead from the stabilizer is compressed and sent to the Export Gas
compressors.
The Cold System uses a propane refrigeration system to chill the gas for pretreatment and
NGL recovery. The membrane operates cold and extensive cross exchange is used to
reduce the duty on the propane system.
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88th Annual Convention, March 8-11, 2009
Gas Processors Association
The “Warm System” first uses cross exchange to condense a small amount of water and
hydrocarbons from the feed stream before entering a MemGuard pretreatment system.1
This pretreatment system, based on temperature-swing adsorption (TSA), simultaneously
removes water, heavy hydrocarbons and mercury from the feed gas. The regenerative
system operates much like a molecular sieve dehydrator, but uses proprietary UOP
adsorbents to remove hydrocarbons and elemental mercury together with the water.
After pretreatment the gas is heated using heat transfer fluid supplied from the permeate
compressor waste heat recovery system. The Separex membranes, which operate close to
ambient temperature, then remove the CO2 to specification. The product gas is then
chilled using propane refrigeration to recover NGL.
In both cases, the membranes utilize a two-stage configuration in order to obtain high
hydrocarbon recovery (minimum 95%) while removing more than 87% of the CO2 from
the feed stream. In a two-stage system, the permeate stream from the primary
membranes is compressed and processed in the second stage membranes to improve
hydrocarbon recovery.2
The Warm System uses much less refrigeration chilling the membrane residue stream
when compared to the Cold System which chills the entire feed stream. In the Cold
System it is impossible to operate the membrane system without NGL recovery as the
chiller is imperative to provide adequate membrane pretreatment. Hence, a redundant (2
x 100%) refrigeration compressor is required in the Cold System design. This is not the
case for the Warm System, where NGL recovery is independent of CO2 removal.
Mercury Removal Design
The production company specified a mercury level in the feed gas as a precautionary
measure, so it was desirable that mercury removal be achieved with minimum impact on
plot space, platform weight and total cost. Conventional mercury removal can be
achieved with non-regenerable absorbent beds on the main process feed gas line. These
vessels can be very large and expensive to operate due to periodic replacement of the
absorbent. Offshore, additional plot space and support steel significantly increases the
total installed cost.
UOP has a unique technology offering for regenerable mercury removal that is integrated
into the MemGuard pretreatment system, meeting the production company’s
precautionary design intent along with space, weight and cost objectives. UOP HgSIV™ adsorbent selectively removes vapor-phase elemental mercury from the feed gas
during the adsorption step.3 Mercury is then desorbed during high-temperature
regeneration, which has the effect of concentrating the mercury into a stream that is less
than 10% of the feed gas flow rate. A very small non-regenerative guard bed using UOP
GB-562 absorbent is installed on the regeneration gas stream. GB-562 absorbent is
metal-oxide-based. After being sulfided in-situ via reaction with H2S, it chemically
reacts with mercury and holds it tightly. Periodic replacement is required and
reclamation of the metals in the absorbent is recommended.
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Gas Processors Association
For the system under discussion, mercury is removed from a design concentration of 40
µg/Sm3 to less than 5 µg/Sm3. The hot regeneration gas stream contains roughly 500
µg/Sm3 of mercury. After air cooling, water and hydrocarbons are removed in the
regeneration gas separator at 45ºC. Although no condensation of mercury is anticipated
at these operating conditions, the regeneration gas separator is equipped with a low point
mercury trap, just as a precaution. A very small non-regenerative guard bed using UOP
GB-562 absorbent is installed downstream of the spent regeneration gas separator to
permanently remove mercury from the system.
Depending upon the water, hydrocarbon and mercury removal requirements for
pretreatment, the use of Hg-SIV adsorbent may or may not require an increase in the total
size and weight of the MemGuard system adsorbers. For this system, there is no increase
in adsorbent bed size due to the low concentration of mercury in the feed stream. The
size of the non-regenerative guard bed on the regeneration gas stream is very small
compared to the large absorbers that would be required for conventional mercury
removal.
Stabilizer Design
In the Cold System the NGL feed to the stabilizer contains significantly more CO2
compared to the Warm System. This results in a larger diameter column to handle the
additional vapor flow and a larger reboiler to produce the 12 psia Reid vapor pressure
NGL product. No matter where the overhead vapors are to be sent, some compression is
required. The Cold System requires a larger overhead compressor to capture vapors
containing a higher percentage of CO2.4
An early decision was taken to compress the overhead vapors and mix them with gas
exiting the membranes for final export compression into the pipeline. The consequence
of this scheme is that the membranes must produce a lower CO2 specification so that the
blended product stream meets the 8% CO2 pipeline specification. In the Cold System,
which produces a stabilizer overhead with high volume and high CO2 content, the
membranes must reduce CO2 levels to a greater degree versus the Warm System, which
produces less stabilizer overhead vapors with lower CO2 content.
Flare System Design
API Recommended Practice Numbers 521 and 14C for offshore natural gas operations
state that the system should depressurize from operating pressure to less than 100 psig
within 15 minutes. A study was conducted to determine the effect of this guideline on
the flare headers for both the Cold and Warm Systems.
While vapor volumes are similar for the Cold and Warm Systems, the amount of liquids
held in various vessels is significantly higher for the Cold System. When equipment
pressures are rapidly reduced, liquefied gases expand to add volume that must be
accounted for in flare header sizing. Once again, the Warm System proves to be lower in
cost.
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Gas Processors Association
Final Process Scheme Selection
When all of the equipment for these two options was laid out in an optimum fashion and
then supported by platform jacket steel, the overall cost of the process scheme was
assessed. During the comprehensive evaluation period, the Warm System consistently
proved to be the option with the lowest installed cost. Table 3 summarizes the
comparison between the options.
Table 3 – Comparison of Process Schemes
Major Equipment
Overall Compression
Refrigeration Equipment
Mercury Removal Equipment
Heating Duty
Stabilizer System
Flare System
*Uses Waste Heat Recovery
Cold System
More
More Duty and
Spare Compressor
More
Less
Larger
Larger
Warm System
Less
Less Duty and
No Spare Required
Less
More*
Smaller
Smaller
Platform Design
The Separex membrane system and the MemGuard pretreatment system were fabricated
under the supervision of UOP according to the basic and detailed designs. Local Asian
fabrication was maximized. None of the equipment provided by UOP required premium
top deck installation, which was reserved for compressors and air coolers.
In order to make the air coolers of uniform size, the platform fabricator procured the
MemGuard system regeneration gas air cooler based on UOP specifications and installed
it along side other air coolers which operated in various process applications. All of the
other individual exchangers, vessels and membranes were installed on lower decks.
One of the advantages of Separex membrane systems in offshore applications is that the
individual membrane elements are small and light enough to be handled by a single
operator without special lift equipment. Loading the UOP spiral-wound cellulose acetate
elements in horizontal housings helps to minimize unused space required for
maintenance. Only 1 to 2 meters of work space is required at each end of the housing to
accomplish element change-out. The membrane housings are grouped on wide, low
skids, fitting nicely between decks with maximum packing density. Placing membranes
on lower decks helps to lower the center of gravity for the platform and reduce jacket
support steel.
The MemGuard pretreatment system adsorbers require access to a crane for loading and
unloading. This is accomplished by installing the vessels along the edge of one side of
the platform on a mid-level deck. The switching valves used to automatically move
between the adsorption and regeneration steps (temperature swing system), are installed
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Gas Processors Association
on a skid adjacent to the vessels on the outboard side. This arrangement locates the
heavier vessels closer to the center of the platform while lowering the center of gravity
and still allowing overhead access to the crane. UOP employed a unique three-tier design
for the valve switching skid. This places the valves for the inlet and outlet of each vessel
at the same height as the connecting piping. Large diameter piping headers run through
the center level of the skid. A three-dimensional model is shown in Figure 3.
Figure 3 – 3-D Model and Photograph of the MemGuard Pretreatment System
Redundant (2 x 100%) filter coalescers and particle filters are installed in stacked skids
(Figure 4). The upstream filter coalescers prevent liquid contamination of the
MemGuard adsorbent while the downstream particle filters remove any dust exiting the
adsorbers. Stacking the vessels saves plot space while keeping piping runs to and from
the adsorbers as short as possible.
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Gas Processors Association
Figure 4 – 3-D Model of Stacked Filter Coalescer Design
Platform Fabrication
Due to the construction method of integrating equipment into the platform decks, on-time
delivery of the equipment is critical to maintaining schedule. As each deck is
constructed, all the required equipment must be installed on that level before proceeding
to the next higher deck. All the equipment and skids delivered by UOP arrived within the
required construction time line.
As is typical of projects this large and complex, delays in installation occurred and some
of the delivered equipment sat in the platform fabrication yard for weeks. Due to the
marine environment in the yard, preservation of the equipment must be carefully
maintained to avoid rust formation. Precautions must be taken prior to shipment of
equipment to seal the steel against the environment. The closed equipment should be
purged with nitrogen and kept under an inert blanket which requires regular monitoring at
the yard. This prevents moisture-laden, corrosive air from entering the equipment. A
small portion of UOP’s equipment rusted despite efforts to prevent corrosion. The rust
was removed during installation and new quality maintenance procedures have been
implemented for future projects.
Another area for close collaboration with the platform integrator is the support of piping
at equipment nozzles. This is particularly critical for heat exchangers where nozzles may
not be designed to carry as much piping stress as on larger vessels. Flange leaks can be
an issue if lack of piping support induces stress that was not anticipated in the nozzle
design.
System Automation
The temperature swing process of the MemGuard unit requires automated control and
switching of the vessels step-wise through the process. UOP provides complete
programming for the unit in one of two ways. A programming specification can be
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Gas Processors Association
delivered for use in Distributed Control Systems (DCS) with programming supplied by
others. UOP process and controls engineers oversee extensive testing once the
programming is complete. Alternately, a complete Programmable Logic Controller
(PLC) with all programming already installed and tested can be delivered by UOP as a
slave unit to the DCS. For this project, the customer selected Honeywell Automation &
Control Solutions (in Asia) to program their Honeywell DCS system. As an example,
one of the MemGuard system screens used at the Human Machine Interface (HMI) is
shown in Figure 5.
Figure 5 – HMI Screen for MemGuard Pretreatment System
(Sample only – not in operation)
In many membrane applications, starting operation of the membrane skid is handled
manually and shutdown is automated. The customer requested that the operation of the
membrane unit be fully automated for this project. UOP installed automatic controls on
all the startup valves and implemented programming to automate the startup and
shutdown sequences. This provides a “push button” operation from start to finish. A
sample of one of the second stage membrane control screens is shown in Figure 6.
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88th Annual Convention, March 8-11, 2009
Gas Processors Association
Figure 6 - HMI Screen for Second Stage Membranes
(Sample only – not in operation)
System Startup
As the first-gas-in startup date approached, the feed stream was expected to contain 30 –
35% CO2 versus the design value of 44.5%. In anticipation of processing this gas, the
number of elements loaded in the tubes was reduced to optimize the performance of the
unit.
Gas first flowed to the platform mid-March of 2007 at very low flow rates. From day one
the system met the CO2, water and mercury specifications for the sales gas. Membrane
sections (skids) were put in operation such that membrane area matched the amount of
gas to be treated. Startups and shutdowns, not related to the UOP system, were frequent
during this period. In particular, compression issues caused many shutdowns and restarts.
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Gas Processors Association
The inlet gas rate steadily increased through the next several months as additional wells
were tied into the gathering system. During this time, several mechanical issues were
corrected. Specific to the UOP supplied equipment, this included:
•
•
•
Repair of the MemGuard system recycle blower (compressor) impellor which
had failed due to debris in the suction piping,
Vendor repairs of the on-line gas chromatographs, and
Stoppage of hot oil flange leaks at the membrane pre-heaters by replacing flange
rings, repairing flange sealing surfaces and adding new pipe supports.
Once the unit operation was stabilized and optimized, a performance test was conducted
in October of 2007 over a 26-hour period. Extensive testing was done to confirm the
system material balance. Data was obtained from the Honeywell DCS system. Daily
averages are shown in the second column of Table 4. The on-line gas chromatographs
used for CO2 and hydrocarbon analysis were re-calibrated by the supplier before the test.
After identifying one flow meter that was indicating lower than expected rates (despite
efforts at re-calibration), minor adjustments of the remaining field data were adequate to
close the material balance around the unit.
Table 4 – Performance Test Results
Case
Feed Flow, MMSCFD
Feed Pressure, kPag
Feed Temperature, ºC
Feed Composition, Mole %
Nitrogen
CO2
H2S, ppm
H2O
Methane
Ethane
Propane
C4+
Mercury, µg/Sm3
Sales Gas Flow, MMSCFD
Membrane Area, %
Sales Composition
CO2
H2S, ppm
H2O, lb/MMSCF
Mercury, µg/Sm3
Hydrocarbon Recovery, %
Design
October 2007
Norm
Test
Extrapolated
401
581
591
4000 Min
3736
4000
47 Max
35
35
0.8
44.5 Max
20 Max
.2
46.6
4.2
1.9
1.5
40 Max
320 Min
100
1.0
38.7
<1
0.3
53.3
4.5
1.7
1.1
n/m
201
60
0.9
44.5
20
0.2
47.6
4.0
1.6
1.2
40
320
100
8.0 Max
10 Max
5 Max
5 Max
95.0 Min
7.6
0.05
0.06
n/m
95.8
8.0
<10
<1
<5
95.7 – 96.0
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Gas Processors Association
Because the feed CO2 content and feed gas flow rate were well below design basis values
during the performance test, the test data were extrapolated to determine the performance
at design values (third column of Table 4). The test data were used to calibrate UOP’s
proprietary simulation model and calculate the actual membrane performance properties
at the test conditions. The system parameters where then adjusted to increase the feed
CO2 to design of 44.5%, bring the sales gas up to 8.0%, and increased feed flow to the
rate required to deliver the minimum 320 MMSCFD of sales gas. This final step was
modeled with the design amount of primary and secondary membrane area on-line,
whereas the test was done with only about 60% of the design area on-line. This
extrapolation demonstrated that the unit met system design requirements and will achieve
better hydrocarbon recovery by producing 320 MMSCFD of sales gas with less than the
591 MMSCFD feed rate used as the design basis.
The performance test results were reviewed with the client, who subsequently accepted
unit as having met capacity, product specification and hydrocarbon recovery targets.
Recent Operation
UOP continues to support the operation of the unit with an on-going contract that
includes daily data monitoring. With new wells being added in mid 2008, the feed CO2
increased to near design value of 44.5% and additional feed gas quantities were available
for processing. The unit now operates at near design conditions per Table 5.
Table 5 – Recent Unit Performance
Date
Feed Flow, MMSCFD
Feed Pressure, kPag
Feed Temperature, ºC
Membrane inlet Temperature, °C
Feed Composition, Mole %
Nitrogen
CO2
H2S, ppm
H2O
Methane
Ethane
Propane
C4+
Mercury, µg/Sm3
Sales Gas Flow, MMSCFD
Sales Composition
CO2
H2O, lb/MMSCF
Mercury, µg/Sm3
Hydrocarbon Recovery, %
Oct 10, 2008
533
4016
31
48
Oct 25, 2008
485
4136
32
41
1.1
43.7
0.7
37.2
<1
48.9
3.5
1.5
1.3
n/m
306
55.0
4.3
1.6
1.2
n/m
320
7.7
On spec
n/m
93.2
7.7
On spec
n/m
96.4
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Gas Processors Association
As CO2 levels rose, monitoring of individual skid performance indicated that three
sections of the primary membranes were performing below expectation. Adjustments
were made by increasing the operating temperature at the membranes. While this
improves the CO2 removal performance, it also decreases hydrocarbon recovery (see
October 10th data). At lower CO2 feed gas levels (October 25th data), the unit can
produce the minimum product gas rate with very good hydrocarbon recovery.
During a November 2008 shutdown, the three underperforming skids were opened for
addition of new elements (to account for the increase in feed CO2 levels versus startup
conditions) and for inspection. The first elements in these skids were found to be
damaged by water and debris. These elements had been damaged during the initial
startup period. In spite of line cleaning, construction debris had not been completely
removed. The startup in-line strainers on the feed piping were plugged and were cleaned
multiple times during the first several weeks of operation. Closer collaboration with the
system fabricator can reduce or eliminate startup damage by more carefully monitoring
line installation, cleaning and prevention of moisture accumulation.
Despite the early damage to the lead membrane element, the system continued to perform
adequately at reduced rates. This is one of the operational benefits of using Separex
membrane elements in series in contrast to very large membrane elements installed in
parallel. Contaminants do not typically reach downstream elements, so replacing only
the first membrane element in each membrane tube is sufficient to restore the
performance.
The damaged lead elements were replaced and additional elements added during the
scheduled shut down. No special lifting equipment was required. Less than 6% of the
first stage membrane elements were replaced. The vast majority of the elements in the
primary membrane stage will pass two years of service with little reduction in
performance. There has been no replacement of second stage elements to date.
Conclusion
Large offshore gas processing projects are complex and expensive to build. By working
closely together, the end user, platform fabricator and technology suppliers can
economically complete the projects, meet expected performance goals and realize
operational and maintenance benefits. Close collaboration in the early phases of design is
essential to arriving at a system design that ensures the lowest installed cost.
The UOP MemGuard and Separex process systems, with downstream NGL recovery,
meet the specific customer requirements for this project. As of March 2009, the system
is operating for two years meeting specifications and without significant membrane
replacement.
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References
1. Koch, D.R., Buchan, W.R. and Cnop, T., “Proper Pretreatment Systems Reduce
Membrane Replacement Element Cost and Improve Reliability”, 84th Annual
Convention Proceedings, Gas Processors Association (2005).
2. Brown, W.G., “Gas Treating Technologies: Which Ones Should be Used and Under
What Conditions?”, 87th Annual Convention Proceedings, Gas Processors
Association (2008).
3. Markovs, J. and Clark, K., “Optimized Mercury Removal in Gas Plants”, 84th Annual
Convention Proceedings, Gas Processors Association (2005).
4. Echt, W.I. and Singh, M., “Integration of Membranes into Natural Gas Process
Schemes”, 87th Annual Convention Proceedings, Gas Processors Association (2008).
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