INTEGRATED TECHNOLOGY IN PROCESSING HIGH CO , …

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John Mak, Fluor Energy & Chemicals

INTEGRATED TECHNOLOGY IN PROCESSING

HIGH CO2, HIGH N2 OFFSHORE GAS FOR LNG

PRODUCTION

Authors: John Mak, Tang Bin, Curt Graham

Affiliate: Fluor Energy & Chemicals

Abstract

In many offshore gas reservoirs, the produced gas is a lean gas, but often has high CO2

content ranging from 30% to 60%, with nitrogen content higher than 5%. These gases are

left untapped due to their low heating values, and difficulties in treating to meet the sales

gas specification. Locating in an offshore environment adds complexity to the processing

facility, due to space constraints, stringent safety requirements, limited utility supply, and

limited staffing for operation and maintenance. Even after the gas is treated for CO2

removal, transportation to onshore requires long distant pipe lines.

The innovation disclosed here is a Fluor Solvent process that is specifically designed for

offshore installation for CO2 removal. The Fluor Solvent process is proven to be an

economic process for high CO2 gas removal. It is a non-heated process that can eliminate

fuel gas consumption, avoiding greenhouse emissions. The process utilizes the potential

energy in CO2 to generate refrigeration, thus minimizing the power consumption in CO2

removal.

For LNG production for high nitrogen gas, the treated gas must be processed in a nitrogen

rejection unit to reduce its nitrogen content to less than 1 mole%. The integrated process

utilizes the rejected nitrogen from the nitrogen rejection unit as a stripping gas in the Fluor

Solvent unit, which can treat the feed gas to below 200 ppmv CO2, further reducing the CO2

removal requirement for LNG liquefaction.

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Introduction

Offshore gases, such as from South China Sea and Pre-salt regions are high in CO2 content and N2 content, which

are costly to develop with conventional treating technologies. Even when these gases are treated to meet pipeline

specifications, the pipeline cost for transporting to on-shore facilities is an additional cost. One of the methods is to

liquefy the treated gas such that it can be transported by ship, avoiding the high cost of undersea pipelines. To

develop these untapped resources, innovative methods on treating these high CO2 gases to meet LNG

specifications are necessary.

An innovative process was developed using the Fluor Solvent process which has been specifically designed for

offshore operation. The integrated process would avoid the use of external heating, and cooling, producing a

product gas with minimum CO2 and nitrogen, suitable for LNG liquefaction.

Offshore Design Considerations

From a design and operation standpoint, an offshore gas treating facility requires a different focus than an onshore

facility. Daily routine operations that are taken for granted onshore can present serious problems offshore.

Operationally, the focus offshore needs to be on safety, simplicity, and reliability. Offshore operation must consider

environmental requirements, corrosion mitigation, and operational flexibility. The facilities are limited in staffing,

which makes monitoring and controlling a complex process difficult. Equipment modifications are restricted and are

difficult to accommodate higher CO2 content if necessary.

From a construction and cost standpoint, an offshore treating plant should have a minimum equipment count. This

usually results in a smaller platform footprint and less weight for the jacket to support. Eliminating fired equipment

reduces equipment safety spacing requirements and makes the platform footprint smaller. Eliminating a steam or

heat medium system, or water supply system reduces the total equipment count and simplifies plant operation.

Treating Options

For small gas plants, membrane separation has been installed offshore for high CO2 removal. These units are

compact and can be installed at a lower cost than conventional process. However, membrane separators are

designed for bulk acid gas removal, and their hydrocarbon loss is relatively high. The membrane permeate

contains substantial amounts of hydrocarbons, which must be recycled or reinjected to formation to avoid releases

of greenhouse gases. There is also no economy of scale with membrane units. Multiple identical units are required

to handle higher CO2 content or larger flow rates. When hydrocarbon recovery is required, membrane separation is

not a good choice, especially for larger plants.

Common solvent treating processes are the amine treating and the physical solvent treating technologies. Amine

treating is typically used for low CO2 content gases. Amine unit requires heating with steam or hot oil and cooling

with ambient air or cooling water for amine regeneration. The fuel consumption and water usage by the amine units

are operational and environmental issues for offshore operation. Hence, amine process is not suitable for treating

high CO2 gas for offshore operation.

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Physical Solvents

Physical solvent uses less energy than amine processes. The solvent can be regenerated by pressure letdown,

and can reduce heating consumption. The Fluor Solvent process uses propylene carbonate (PC) as the physical

solvent proven for treating high CO2 gases. The process is competitive to amine treating when the partial pressure

of the CO2 content is higher than 50 psi.

Physical solvents have an advantage over chemical solvents when treating high CO2 partial pressure gases in that

the physical solvent gas holding capacity (volume of CO2 per unit of solvent circulation) increases proportionally

with the CO2 partial pressure according to Henry’s law. This is different from chemical solvent, such as amines,

which loading is solely determined by chemical equilibrium, independently of CO2 partial pressure. These two

relationships can be illustrated in Figure 1.

Figure 1 – Solvent Rich Loading- Physical Solvent versus Amine

The Fluor Solvent Process, which was originally commercialized by Fluor in the early 1960s, uses propylene

carbonate (PC) as the solvent for the removal of CO2 and H2S from natural gas and synthesis gas streams.

Propylene carbonate, C4H6O3, is a polar solvent that has a high affinity for acid gases. For cases where the CO2

content that changes over time, the Fluor process unit can be operated with the same circulation, as the rich

loading would increase with the higher CO2 partial pressure. This operation has been demonstrated in the earlier

Fluor Solvent plants described in the following section. On the contrary, amine units would require higher amine

circulation with additional trains to handle the higher acid gas contents.

Most of the equipment in the amine unit is constructed of stainless steel to avoid wet CO2 corrosion. The Fluor

Solvent process operates under a dry environment, and there are no water makeup or corrosion problems with the

use of PC. The Fluor Solvent system is constructed of carbon steel. The PC is also a non-toxic and non-foaming

solvent. The following table is a comparison of a promoted MDEA unit to the Fluor Solvent unit for high CO2 gases.

Physical Solvent

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Table 1 – Fluor Solvent vs promoted MDEA for High CO2 Gases

Fluor Solvent Promoted MDEA

Equipment Count Lower Higher

Operational Complexity Lower Higher

Stainless Steel Materials No Yes

Stress Relieving of Carbon Steel No Yes

Fired Heat Required No Yes

Modification for Increasing CO2 in feed Minimal Substantial

Vulnerable to Solvent Foaming No Yes

Winterization Required No Yes

Solvent Concentration Monitoring No Yes

Non-Toxic and Biodegradable Solvent Yes No

Produces Dry, Cold Treated Gas Yes No

Hydrocarbon Content of Acid Gas Higher Lower

Feed Gas Shrinkage Lower Higher

Net Sales Gas Delivery Higher Lower

There are other physical solvents that can be used to remove CO2. For example when compared to DMPEG

(dimethylether of polyethylene glycol), PC has a higher affinity towards CO2 and a low solubility of hydrocarbons,

and can operate at as low as -20°F. Lower solvent temperature would increase the rich solvent loading, which

lowers solvent circulation and reduces hydrocarbon losses. Regeneration of DMPEG would require external

heating while the Fluor process is a non-heated process.

Fluor Solvent Plants

PC plants can be designed to operate under ambient temperature, which are common in China for ammonia

production. Ambient PC plant requires higher solvent circulation which would also increase co-absorb of

hydrocarbons. The Fluor Solvent design is configured to operate under mildly refrigerated temperatures, to reduce

solvent circulation and hydrocarbon losses. Two of the earliest Fluor Solvent plants are described in the following.

Terrell County Natural Gas Plant

The Terrell County Fluor Solvent plant, located in Terrell County, Texas, was built in 1960s. The plant was

designed to treat natural gas to meet 2 mole% CO2 specifications. The original plant was designed to treat 220

MMscfd feed gas with 53 mole% CO2 and contains about 70 ppmv of H2S. The low pressure feed gas was

compressed to about 900 psig pressure to feed the absorber. Currently, the gas plant is supplied from a different

source, and is processing about 120 MMscfd of feed gas with 36 mole% CO2 at 650 psig.

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The Fluor process uses four flash stages for solvent regeneration, with the last stage operating under vacuum

pressure, as shown in Figure 2. A small amount of refrigeration is

used on the rich solvent to lower the solvent temperature. A

hydrocarbon re-absorber was used to reduce the hydrocarbon

content in the CO2 vent gas to meet the emissions requirements of

2%.

While the non-heated process can reduce the CO2 content to 2

mole% to meet specifications, the process, being a non-heated

process, can only reduce the H2S content from 70 ppmv to about 6

ppmv. Subsequently, a sulfur scavenger bed was added on the

treated gas to meet the 4 ppmv pipeline gas specification

The process unit has been successfully operating with the same equipment for over 50 years.

Treated Gas

Re-absorber

Refrig

Absorber

MP

Drum

Solvent PumpHydraulic

Turbine

LP Drum

HP Drum

Vacuum

Drum

Cond.

CO2 Vent

Refrig

Feed Gas

650 psig

Sulfur Scavenger

180 psig

60°F

27°F

4 ppm H2S

2% HC

Figure 2 – Terrell County Fluor Solvent Process Flow Diagram

Terrell County Fluor Solvent Plant

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Woodward Oklahoma Syngas Plant

The Woodward Oklahoma Fluor Solvent plant was built in 1977 for ammonia production. The process was used to

treat 148 MMscfd syngas operating at about 1,860 psig. The syngas

contains about 22 mole% CO2 and 4 ppmv H2S. The Fluor can

remove the CO2 content to meet the 200 ppmv specifications

required for ammonia production.

The solvent is regenerated with a high pressure drum and a low

pressure drum. Flash gas from the medium pressure drum is

recycled to the feed gas section. Flash gas from the low pressure

drum is mainly CO2 which is used for enhanced oil recovery or for

urea production.

Since the syngas is almost H2S free, the solvent can be regenerated using a dry air stripper. With air stripping, an

ultra-lean and dried solvent can be regenerated which can meet the 200 ppmv CO2 specification in a relatively

dried treated gas. The process flow diagram of the Woodward Oklahoma plant is shown in Figure 3.

It should be noted if the feed gas is first treated for sulfur removal, dry air or dry nitrogen can be used as a stripping

gas in PC regeneration to achieve a very low CO2 content and dried treated gas.

Treated Gas

Solvent Stripper

Absorber

Solvent Pump

Hydraulic

Turbines

HP Drum

Refrig

Feed Gas

1850 psig

1860 psig

50°F

15°F

Dry Air

CO2 for EOR

Flash GasLP Drum

Figure 3 – Woodward Oklahoma Fluor Solvent Process Flow Diagram

Woodward Oklahoma Fluor Solvent Plant

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The Innovations

With conventional amine treating process, high CO2 content gas would require higher solvent circulation, heating

and cooling duties, which requires high capital and operating costs, reducing the treating economics. Based on

extensive plant operation and thermodynamic data, Fluor has developed a highly efficient PC solvent process,

making treating high CO2 gases an economical option. Some of the key design features for this new process are:

Feed gas is first treated in a sulfur scavenger unit to remove all the H2S to produce a sulfur free feed gas.

Use of two absorbers, with a semi-lean solvent produced from the upper absorber which is chilled for re-

absorption in the lower absorber.

Heat generated from CO2 absorption is used in heating the rich solvent for solvent regeneration.

Refrigeration generated from flash solvent is used to cool the feed gas and the semi-lean solvent.

Hydraulic turbine is used to recover the power from the pressure letdown and to generate refrigeration for

CO2 absorption.

Hydrocarbon losses are minimized by recycling flash gases from the separators to the absorber.

Use of dry air or dry nitrogen for stripping to produce an ultra-lean PC.

Process Description

The process flow diagram for the new Fluor Solvent process is shown in Figure 4. To produce a sulfur free gas, the

feed gas is first treated in a sulfur scavenger unit. The sulfur free gas is then dried in a dehydration unit to prevent

water from forming hydrate in the absorber.

The dried gas is then combined with recycle gas from the flash gas from the separators. The combined stream is

cooled by heat exchanged with the treated gas and the chilled flashed solvent. Heavy hydrocarbons are separated

in a separator before the absorber. If the feed gas is a rich gas, heavy hydrocarbons can be separately processed

and recovered, in order to reduce the hydrocarbon loss from the CO2 waste stream.

For offshore configuration, where there is a platform height limitation, the use of a two-stage absorber system

would be suitable. For land based plant where there is no height limitation, a single absorber with a side-draw can

be used instead. The feed gas is first scrubbed in the lower absorber using a semi-lean solvent from the upper

absorber. The semi-lean solvent is cooled by the chilled flashed solvent from the medium pressure flash drum,

supplemented by external refrigeration if necessary. The residual CO2 from the lower absorber is removed in the

upper absorber, to meet the required CO2 specification.

The rich solvent from the lower absorber is letdown in pressure in the hydraulic turbine, and separated in the high

pressure drum. For high pressure CO2 gas, the cooling effect from the hydraulic turbines can supply most of the

process refrigeration requirement; external refrigeration is not needed. For a high pressure feed gas, the hydraulic

turbine can supply about 50% of the total pumping power. The separator vapor, containing the bulk of methane, is

compressed and recycled back to the absorber. The flashed liquid is letdown to the medium pressure drum with a

letdown valve, producing a flashed vapor, which is also recycled back to the absorber.

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Flashed liquid from the medium pressure drum is heated by the feed gas and the semi-lean solvent, which helps to

regenerate the solvent. The refrigerant content of the rich solvent cools the feed gas and the semi-lean solvent,

which helps CO2 absorption. The dual heat exchange process reduces the solvent circulation and the hydrocarbon

losses.

The solvent is further letdown in the low pressure drum at atmospheric pressure, producing a CO2 stream with 97

to 98% purity, which can be further compressed for CO2 sequestration. The low pressure solvent is further letdown

to a stripper using dry air or nitrogen as the stripping medium.

Using dry nitrogen or dry air, the stripper can produce an ultra-lean solvent to meet the 200 ppmv CO2 treated gas

specification. The dry stripping operation has been successfully used in the Woodward Oklahoma ammonia plant

for ammonia production as previously described.

Mole

Sieve

Feed Gas

Treated Gas

CO2 to

Sequestration

Refrig

Semi-RichAbsorber

Lean Absorber

Recycle Compressor

MP Drum

Solvent Pump

Inter-Pump

Hydraulic Turbine

LP Drum

HP Drum

SolventStripper

Cond.Nitrogen or

Dry Air

Vent

H2S

Scavanger

100 MMscfd

24 to 32 mole%CO2

<10 ppmv H2O

<200 ppmv CO2

Figure 4 – New Fluor Solvent Process Flow Diagram

Applications

A case study is used to demonstrate the process performance of the new process for two high CO2 gases: 24

mole% and 32 mole%, as shown in Table 2. The feed gas rate is 100 MMscfd, supplied at 1130 psig pressure and

80°F temperature. The process requirements are to produce a treated gas with minimum CO2 with hydrocarbon

losses limited to 1%.

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Table 2 – Feed Gas Compositions

Feed Gas 24 mole% CO2 32 mole% CO2

Mole %

N2 11.9 7.80

CO2 24.3 32.0

CH4 62.1 58.3

C2H6 1.0 1.10

C3H8 0.20 0.30

IC4 0.10 0.10

NC4 0.10 0.10

IC5+ 0.20 0.30

Process Performance

The power consumption, utility and chemical consumption for the two feed gases are shown in Table 3. As

expected, the same solvent circulation can be used for different CO2 concentration gases, similar to the Fluor

Solvent Terrell plant operation.

When these two cases are compared, the power consumption for the 32 mole% CO2 gas is higher. The higher

power consumption is because more CO2 is flashed off in the interstage flash drums, and a larger recycle

compressor is larger. On the other hand, the larger amount of flashing produces more cooling; therefore,

refrigeration is not required for the 32 mole% CO2 case.

Table 3 – Utility Consumption

24 mole% CO2

24 mole % CO2

32 mole % CO2

Treated Gas, CO2 mole % 200 ppmv 200 ppmv

Hydrocarbon Losses: 1% 1%

Power Consumption:

Hydraulic Turbine, kW -844 -950

Circulation Pump, kW 1,569 1,628

Recycle Compressor, kW 772 1,374

Vacuum Pump, kW 172 153

Refrigeration, kW 145 Not Required

Total Power, kW 1,814 2,205

Utility and Chemicals:

Solvent Circulation, m3/h 461 477

Solvent Makeup, kg/h 0.42 0.47

Water Makeup, kg/h No No

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Nitrogen Rejection

With removal of the CO2 content, heating value of the treated gas is increased, but at the same time, its nitrogen

content is concentrated to 11-16 mole %, as shown in Table 4. The nitrogen content must be removed to meet

pipeline specification, typically at 2 to 3 mole %. When used as a feed gas to an LNG liquefaction plant, the

nitrogen content must be removed to below 0.5 mole %, as high nitrogen would lower the liquefaction temperature,

making LNG liquefaction more difficult. Higher nitrogen is also not desirable, as it will increase the vapor boiloff rate

from the LNG storage tanks.

Table 4 – Treated Gas Compositions

Feed Gas 24 mole % CO2 32 mole % CO2

Mole %

N2 16.14 11.5

CO2 0.00 0.00

CH4 82.84 86.77

C2H6 0.92 1.42

C3H8 0.10 0.31

IC4 0.00 0.00

NC4 0.00 0.00

IC5+ 0.00 0.00

Nitrogen Rejection Unit

For LNG production, the water content and CO2 content in the feed gas must be removed. The water content must

be reduced to below 0.1 ppmv and CO2 content to 50 ppmv to avoid freezing in the LNG cryogenic exchangers.

This removal operation would require a molecular sieve polishing unit, which is significantly smaller than the

conventional molecular sieve unit. The dried and treated gas is then processed in a typical Nitrogen Rejection Unit

as shown in Figure 5. The unit mainly consists of a cold box, an NRU column, a reflux exchanger and a product

gas compressor.

The treated feed gas is chilled in the cold box, to typically -190°F, and is let down in pressure from 1,100 psig to the

NRU Column typically operating at about 350 psig. Chilling and reflux duties are supplied by the cooling effect from

letdown of the feed gas, and letdown a portion of the NRU column bottoms. The letdown portion of the fractionation

bottom is controlled to meet the refrigeration requirement. In the process, the refrigeration content of the rejected

nitrogen is recovered by heat exchange in the reflux exchanger, before being used as a stripping gas in the

integrated Fluor Solvent process. The low-pressure NRU bottoms are heat exchanged and recompressed to about

800 psig to feed the LNG liquefaction plant.

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Nitrogen to

Stripper

Cold Box

NRU Column

Reflux

Exchanger

Compressor

11 to 16 mole% N2

from Polishing unit

0.5 mole% N2 To Liquefaction

Side Reboiler

Reboiler

350 psig and -250°F

Figure 5 – Nitrogen Rejection Unit

Innovative Integration

In a traditional LNG gas treating process, the feed gas is first treated in an amine unit to meet 50 ppmv CO2 LNG

specifications. The treated gas must be dried in a molecular sieve dehydration unit to below 0.1 ppmv water

content. The traditional amine treating unit and the dehydration unit can be substituted with the following innovative

design.

In the integrated design, the feed gas is treated with a sulfur scavenger bed to remove all the H2S content,

producing a sulfur free treated gas. With dry nitrogen for stripping, the Fluor Solvent unit can produce a treated gas

with 200 ppmv CO2 and 10 ppmv water content. The treated gas can be further processed in a small polishing unit

using molecular sieves to meet the 50 ppmv CO2 and 0.1 ppmv water specifications for LNG feed.

The nitrogen rejection unit can reduce the high nitrogen content in the treated gas to below 0.5 mole%, suitable for

LNG production.

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Figure 6 – Fluor Solvent for LNG Production

Conclusions

Traditional amine unit and dehydration unit are not economically viable to treat high CO2 and high N2 gas for LNG

production, due to the high heating and cooling costs. The new Fluor Solvent process can eliminate both the

heating and cooling requirements of traditional processes. The Fluor Solvent process uses a configuration that

utilizes the energy potential of high CO2 content to generate refrigeration and the use of CO2 absorption heat for

flash regeneration in solvent regeneration.

When coupled with a nitrogen rejection unit, the nitrogen off-gas is used for stripping the PC to produce an ultra-

lean solvent. The innovation reduces the CO2, nitrogen and water content to very low levels, that a small polishing

molecular sieve unit can be used to meet the feed gas specifications to an LNG liquefaction plant. This method has

eliminated the conventional amine unit, and reduced the size of the dehydration unit.

The innovative Fluor Solvent technology is an integration solution that will provide cost savings and environment

benefits for processing the high CO2, high N2 offshore gases for LNG Production.

References

1. Mak, J., Row, V. “Production of Pipeline Gas from a Raw Gas with a High and Variable Acid Gas Content”

GPA Annual Conference, New Orleans, 2012.

2. Mak, J., “Innovative Treating Processes For High CO2 Gas”, Permian Basin GPA Annual Conference,

Midland, Texas, April 30, 2015.

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3. Mak, J., Graham, C., “Coping under Pressure” LNG Industry, July/ august, 2015.

4. Mak, J., U.S. Patent 10,000,713 “Configurations and methods of flexible CO2 removal”, June 19, 2018.

5. Mak, J., U.S. Patent 10,150,926 “Configurations and methods of flexible CO2 removal”, December 11,

2018.