UOP Design Fabrication Startup of Offshore Separex Membrane Tech Paper

8/13/2019 UOP Design Fabrication Startup of Offshore Separex Membrane Tech Paper

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88thAnnual Convention, March 8-11, 2009 Gas Processors Association

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Design, Fabrication and Startup of an Offshore Membrane CO2

Removal System

William Echt

andPeter 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 thatwould 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 gasconditioning makes economic sense.

This paper presents the results of a project to bring offshore natural gas reserves intoproduction for delivery in Asia. The design of the UOP Separex membrane system for

CO2removal 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 CO2removal 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 initialand current operating data.

UOP worked closely with our customer in all phases of the project. The optimizeddesign has proven to meet performance expectations. The UOP system is operating since

March 2007 without significant membrane replacement.


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Introduction

In the summer of 2002, UOP was approached to provide budgetary membrane system

design for CO2removal 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 Separexmembrane 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 paperhighlights and discusses design features that are of general interest as well as those

specific to the Separex membrane unit for CO2removal.

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 toinstall additional oil and gas processing capacity. Fields adjacent to existing offshore

facilities contained significant oil reserves, but the associated gas had CO2levels ranging

from 26 to 55%. By blending producing oil wells with lower-CO2 gas wells, it wascalculated 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 320MMSCFD minimum, with a design capacity of 350 MMSCFD, which translates to a feed

gas flow rate of 590-680 MMSCFD, depending upon the actual CO2content in the feedgas 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 680.0

Pressure (kPag) 4000

Temperature (C) 47

Composition mole %

Carbon Dioxide 44.49Methane 46.63

Ethane 4.18

Propane 1.94

C4+ 2.76

Nitrogen 0.84

Water Saturated

Mercury 40 g/Sm3


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Table 2 Product Gas Specification

Flow (MMSCFD) Minimum 320

Composition Specifications

Carbon Dioxide < 8.00 mole%

Water


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Figure 1 Cold System

(Future)

Feed

Compressionand Cooling

Dehydration

Mercury

Removal

AndPretreatment

Membrane

Separation

Export

Compression

and Cooling

Downstream

Chilling /

NGLRecovery

Feed

ExportPermeate

NGLNGL

Stabilization

CompressedOverhead

Vapors

Figure 2 Warm System

The Cold System requires upstream dehydration as the feed gas will be chilled belowthe 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 downstreammembrane 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 Gascompressors.

The Cold System uses a propane refrigeration system to chill the gas for pretreatment andNGL recovery. The membrane operates cold and extensive cross exchange is used to

reduce the duty on the propane system.


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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 toambient 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 CO2from

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 streamwhen 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 (2x 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 CO2removal.

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. Thesevessels 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 companysprecautionary design intent along with space, weight and cost objectives. UOP Hg-

SIV adsorbent selectively removes vapor-phase elemental mercury from the feed gas

during the adsorption step.3 Mercury is then desorbed during high-temperatureregeneration, 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 chemicallyreacts with mercury and holds it tightly. Periodic replacement is required and

reclamation of the metals in the absorbent is recommended.


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For the system under discussion, mercury is removed from a design concentration of 40g/Sm3 to less than 5 g/Sm3. The hot regeneration gas stream contains roughly 500g/Sm

3 of mercury. After air cooling, water and hydrocarbons are removed in the

regeneration gas separator at 45C. 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 UOPGB-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 increasein 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 pressureNGL 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 gasexiting the membranes for final export compression into the pipeline. The consequence

of this scheme is that the membranes must produce a lower CO2specification 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, themembranes must reduce CO2levels to a greater degree versus the Warm System, which

produces less stabilizer overhead vapors with lower CO2content.

Flare System Design

API Recommended Practice Numbers 521 and 14C for offshore natural gas operationsstate 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 beaccounted for in flare header sizing. Once again, the Warm System proves to be lower in

cost.


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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 thecomparison between the options.

Table 3 Comparison of Process Schemes

Major Equipment Cold System Warm System

Overall Compression More Less

Refrigeration Equipment More Duty and

Spare Compressor

Less Duty and

No Spare Required

Mercury Removal Equipment More Less

Heating Duty Less More*

Stabilizer System Larger SmallerFlare System Larger Smaller

*Uses Waste Heat Recovery

Platform Design

The Separex membrane system and the MemGuard pretreatment system were fabricatedunder 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 theMemGuard system regeneration gas air cooler based on UOP specifications and installedit 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 theindividual 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 formaintenance. 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 membraneson 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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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 gravityand 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 fromthe adsorbers as short as possible.


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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 therequired 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 ofequipment 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 atthe yard. This prevents moisture-laden, corrosive air from entering the equipment. A

small portion of UOPs equipment rusted despite efforts to prevent corrosion. The rust

was removed during installation and new quality maintenance procedures have beenimplemented 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 maynot 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 nozzledesign.

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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delivered for use in Distributed Control Systems (DCS) with programming supplied by

others. UOP process and controls engineers oversee extensive testing once theprogramming 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 onall 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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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 theunit.

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. Membranesections (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 frequentduring this period. In particular, compression issues caused many shutdowns and re-starts.


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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 werecorrected. 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 flangerings, 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 thesystem 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 CO2and 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 toclose the material balance around the unit.

Table 4 Performance Test Results

Case

Design

Norm

October 2007

Test Extrapolated

Feed Flow, MMSCFD 591 401 581

Feed Pressure, kPag 4000 Min 3736 4000

Feed Temperature, C 47 Max 35 35

Feed Composition, Mole %

Nitrogen 0.8 1.0 0.9CO2 44.5 Max 38.7 44.5

H2S, ppm 20 Max


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Because the feed CO2content and feed gas flow rate were well below design basis values

during the performance test, the test data were extrapolated to determine the performanceat design values (third column of Table 4). The test data were used to calibrate UOPs

proprietary simulation model and calculate the actual membrane performance properties

at the test conditions. The system parameters where then adjusted to increase the feed

CO2to design of 44.5%, bring the sales gas up to 8.0%, and increased feed flow to therate 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. Thisextrapolation 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 thatincludes 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 Oct 10, 2008 Oct 25, 2008

Feed Flow, MMSCFD 533 485

Feed Pressure, kPag 4016 4136Feed Temperature, C 31 32

Membrane inlet Temperature, C 48 41

Feed Composition, Mole %

Nitrogen 1.1 0.7

CO2 43.7 37.2

H2S, ppm


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As CO2 levels rose, monitoring of individual skid performance indicated that three

sections of the primary membranes were performing below expectation. Adjustmentswere 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 startupconditions) 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 completelyremoved. 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 Separexmembrane 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 theperformance.

The damaged lead elements were replaced and additional elements added during thescheduled 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 theprimary 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 caneconomically 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 systemis 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 ReduceMembrane Replacement Element Cost and Improve Reliability, 84

th Annual

Convention Proceedings, Gas Processors Association (2005).

2. Brown, W.G., Gas Treating Technologies: Which Ones Should be Used and UnderWhat Conditions?, 87th Annual Convention Proceedings, Gas ProcessorsAssociation (2008).

3. Markovs, J. and Clark, K., Optimized Mercury Removal in Gas Plants, 84 thAnnualConvention Proceedings, Gas Processors Association (2005).

4. Echt, W.I. and Singh, M., Integration of Membranes into Natural Gas ProcessSchemes, 87

thAnnual Convention Proceedings, Gas Processors Association (2008).

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UOP Design Fabrication Startup of Offshore Separex Membrane Tech Paper

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