INTEGRATED TECHNOLOGY IN PROCESSING

HIGH CO2, HIGH N2 OFFSHORE GAS FOR LNG PRODUCTION

Authors: John Mak, Tang Bin, Curt Graham Affiliate: Fluor & 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 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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John Mak, Fluor Energy & Chemicals

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 loss is relatively high. The membrane permeate contains substantial amounts of , 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.

Physical Solvent

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 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.

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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 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 scavenger bed was added on the treated gas to meet the 4 ppmv pipeline gas specification Terrell County Fluor Solvent Plant

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

Re-absorber

650 psig

Feed Gas 180 psig Absorber 27°F MP Vacuum HP Drum Drum LP Drum Drum

60°F Refrig

Refrig Cond. Treated Gas 4 ppm H2S Hydraulic Solvent Pump Turbine Sulfur Scavenger CO2 Vent 2% HC

Figure 2 – Terrell County Fluor Solvent Process Flow Diagram

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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. Woodward Oklahoma Fluor Solvent Plant

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.

CO2 for EOR 1850 psig

Absorber 15°F

Flash Gas LP Drum 1860 psig Feed Gas

50°F HP Drum Solvent Stripper

Dry Air

Treated Gas Refrig Hydraulic Turbines

Solvent Pump Figure 3 – Woodward Oklahoma Fluor Solvent Process Flow Diagram

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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 , 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.

Recycle Compressor CO2 to Sequestration

Semi-Rich Lean Vent Absorber Absorber

Solvent Stripper Refrig HP Drum MP Drum LP Drum

100 MMscfd 24 to 32 mole%CO2

Feed Gas H2S Mole Inter-Pump Scavanger Sieve

Cond. Nitrogen or Dry Air Solvent Pump Hydraulic Turbine Treated Gas

<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 32 mole % CO2 Treated Gas, CO mole % 200 ppmv 200 ppmv 2 24 mole % CO2 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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Compressor 0.5 mole% N2 To Liquefaction Nitrogen to Stripper

Reflux Exchanger

350 psig and -250°F

NRU Column 11 to 16 mole% N2 from Polishing unit Side Reboiler

Reboiler

Cold Box

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.

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