Hybrid membrane-absorption processes for acid gas...

CRICOS Provider No 00025B

1

Dr Tom Rufford, The University of [email protected]

Acknowledgments: Michael Schlierf, Technischen Universität Müchen, Germany

Hybrid membrane-absorption processes for acid gas removal

This paper was prepared for presentation at the International Petroleum Technology Conference held in Bangkok, Thailand, 14–16 November 2016. A full copy of the paper is available through SPE’s OnePetromanuscript number IPTC-18732-MS.

mailto:[email protected]


2

Highlights

Comparison of (1) conventional MDEA amine absorption and (2) hybrid membrane + amine process to treat sour gas for feed to an LNG plant.

Feeds with 10%mol CO2 no apparent benefits of a hybrid system.

Very sour feed gas with 50%mol CO2 the hybrid system has potential for significant reductions in equipment weight, plant volume, investment costs, and operating costs.


3

Rufford et al. (2012) J. Petroleum Sci. & Eng 95-95:p123-154

Typical LNG process flow scheme


4

This project seeks to evaluate the potential of a hybrid membrane + absorption process to treat sour gas onboard FLNG plants.

Challenges for gas processing in remote or stranded fields

Feed to LNG plant has tight specification, e.g.:• CO2≤50ppmv• H2S ≤4ppmv

To meet these specifications amine plants require large columns, large solvent inventories, high demand for energy.

Floating LNG (FLNG) and micro-LNG plants may need significant reductions in weight, cost, and energy demand.


5

A

B

Membrane unit alone could not achieve 50ppmv CO2

Overview of processes compared


6

Two feed cases based on Roussanalyet al. (2014)

Simulations in Aspen Hysys V8.6

Process metrics considered:Methane slip (MS)Relative energy demand (RED)Dry equipment weightDry installed weightTotal plant volumeEquipment cost & installed costOperating cost

Aspen Process Economic Analyzer

Feed1 Feed2Feed compositions in mole

%Methane 83 41Ethane 5 4.5Propane 2 3.5CO2 10 50H2S 0 1H2O 0 0N2 0 0Temp., °C 40 40Pressure, bar 70 70Flow Nm3/h 590,000 590,000

Summary of methodology


8

50% methyl-di-ethanolamine (MDEA) solvent + piperazine (PZ)Contactor: P=70bar; Mellapak 250Y structured packingStage efficiencies: 0.15 CO2; 0.8 H2SStripper: 1.9 bar, 50ºC

Base Case: 50% MDEA absorption


9

Run absorber hard to get 50 ppmv CO2 for LNG prep. (vs 2% pipeline gas)Optimized solvent rate = 1258m3/h

Feed 1, 10% CO2

Solvent rate required to achieve 50 ppmvCO2 specification


10

Feed1 Feed2CO2, %mol 10 50H2S, %mol 0 1Solvent rate m3/hr 1258 4105Absorber stages 20 20Absorber diameter, m 10 15Stripper stages 7 7Reboiler duty, Btu/gal leansolvent

880 880

Summary amine unit requirements for Feed 1 and Feed 2


11

Membrane separation

unit

Sour feed gas

CO2

Hybrid membrane-amine process


12

Material: cellulose acetate (CA) membraneSelectivity P_CO2/P_CH4 = 15 (Niu and Rangaiah, 2014)Selectivity P_H2S/P_CH4 = 19

Permeate pressure = 1.38 bar

Membrane thickness = 100 nm (i.e. CA thickness on a substrate)

Modeled membrane unit in a user defined subflowsheet

Membrane separation unit model


13

Each mole of CO2 removed in membrane unit reduces solvent rate & reboiler duty required in the amine section. Control = membrane area. Reducing hydraulic load also effects equipment sizing

Feed 1, 10% CO2 Feed 2, 50% CO2 + 1% H2S

Solvent rateBase: 1258m3/hr Hybrid: 1160m3/hr

Solvent rateBase: 4105m3/hr Hybrid: 1360m3/hr

Contactor diameter 15m10m

How much CO2 to remove in the membrane unit?


14

CH4 lost across membrane also accounted in Op Costs.

Process metrics spider plot (log scale)


15

IPTC-18732-MS • A Technical Evaluation of Hybrid Membrane-Absorption Processes for Acid Gas Removal • Dr Tom Rufford

Process metrics Spider plots (linear)


16

No clear advantage of hybrid system for this feed scenario and membrane properties.- 7.8% lower solvent rate in hybrid process, doesn’t impact

column size- 30% drop in energy for reboiler, pumps in amine unitThose benefits offset by:• methane slip in membrane unit• Small increase in equipment weight (MSU + base case amine

unit)• Hybrid process costs all increase

Feed 1 10% CO2 summary


17

For very sour gas feed there is potential to use bulk separation properties of the membrane unit.- 67% reduced solvent rate in hybrid process- 80% reduced equipment weight, 50% reduced plant volume

Methane slips increases ~10% CH4 in feed lost across membrane- Still energy savings allow 40% reduction in operating costs- Methane slip has implications on any CO2 processing/storage

plans

Feed 2 50% CO2 + 1% H2S Summary


18

Key limitations of study

Assumption gas to membrane unit is essentially dry.

Captures estimate of membrane replacement as an annualised cost, but doesn’t capture any effect of fouling on separation performance

We only looked at 10% and 50% CO2 scenarios, didn’t search for feed concentration at which hybrid process becomes preferred option.


19

Highlights

Comparison of (1) conventional MDEA amine absorption and (2) hybrid membrane + amine process to treat sour gas for feed to an LNG plant.

Feeds with 10%mol CO2 no apparent benefits of a hybrid system.

Very sour feed gas with 50%mol CO2 the hybrid system has potential for significant reductions in equipment weight, plant volume, investment costs, and operating costs.


20

This work was funded in part by:• The Australian Research Council (DE140100569)• Technischen Universität Müchen travel support for Michael to

UQ

IPTC attendance supported by SPE Faculty Enhancement Travel Award

Slide 20Acknowledgements


21

Unconventional gas research at UQ

Gas separationsHelium recovery

Membranes (da Costa, Smart)

Adsorption (Rufford, Birkett, Zhu)

GTL/GTX (Rudolph)

Modelling (Do, Bhatia, Birkett)

Electrochemical CO2 reduction

Coal seam gasSolids production issues

Relative permeability

Stress-strain-perm models

Two phase flow in the well bore

Well abandonment

https://ccsg.centre.uq.edu.au/

https://ccsg.centre.uq.edu.au/


22

Cited references

Niu, Mark Wendou, G. P. Rangaiah. 2014. Retrofitting amine absorption process for natural gas sweetening via hybridization with membrane separation (in International Journal of Greenhouse Gas Control 29: 221-230Roussanaly, S., R. Anantharaman, K. Lindqvist. 2014. Multi-criteria analyses of two solvent and one low-temperature concepts for acid gas removal from natural gas (in Journal of Natural Gas Science and Engineering 20: 38-49.Rufford, Thomas E., Simon Smart, Guillaume C.Y. Watson et al. 2012. The removal of CO2and N2 from natural gas: A review of conventional and emerging process technologies (in Journal of Petroleum Science and Engineering 94-95: 123-154.

Slide 22



23


24

Slide 24


Hybrid membrane-absorption processes for acid gas...

Documents

Transcript of Hybrid membrane-absorption processes for acid gas...