Appendix A

Membrane/Amine Hybrid Grissik Gas Plant,1,2,3 Sumatra, Indonesia: Case Study

Introduction
ConocoPhillips operates Grissik Gas Plant (Figure A-1) on behalf of its partners: Talisman Energy Pertamina BPMigas Design basis Gas feed: 310 MMscfd CO2 concentrations Inlet: 30% Outlet: 3% Benefits of membrane/amine hybrid process Have a single stage membrane and utilize the thermal value in the permeate stream, thereby Enjoying the simplicity of a membrane separation process without the use of a recycle compressor while Still avoiding hydrocarbon losses. CO2 rich permeate is sent to an atmospheric burner to produce steam which is used in the amine plant for regeneration. Natural gas exiting the membrane Contains about 15% CO2 Fed to the amine absorption column where CO2 is removed to about 3%. Permeate rich in CO2 exits the membrane at near atmospheric pressure.

Process overview
CO2 removal process uses a membrane/adsorption hybrid process Utilizes both Membrane separation and Amine adsorption Simplified process flow diagram is shown in Figure A-2. Thermal swing adsorption (TSA) unit Removes heavy hydrocarbons Serves three functions Membrane pretreatment Feed gas dehydration Sales gas hydrocarbon dew pointing.

Background
General Considerations
Plant built and commissioned in 1998 without TSA membrane pretreatment Initial well tests indicated minimal amounts of heavy hydrocarbons Subsequently, found not to be the case

DOI: 10.1016/B978-1-85617-982-9.00008-9

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FIGURE A-1 Grissik gas plant.

Gas/liquid separator

Raw feed
300 MMSCFD 1140 PSIG 83 F 30% CO2 120F

TSA Permeate Steam generator

Membrane Dehydration

Retentate 230 MMSCFD 1100 PSIG 99 F 15% CO2 Note: Approximate flows and compositions shown.

Sales gas
Amine absorption column 200 MMSCFD 1087 PSIG 2% CO2

FIGURE A-2 Grissik process flow diagram.

Resulted in sharp reduction in membrane capacity (declining to 2030% of initial capacity within in a month) To maintain production capacity, the membrane elements were being frequently replaced. Installation of TSA ConocoPhillips evaluated heavy hydrocarbon removal processes including

First Commissioning
Membrane initially installed with pretreatment consisting of Coalescing filter and Nonregenerable absorption guard bed. At startup in 1998 Actual levels of heavy hydrocarbons (CO10, aromatics, and napthenes) were higher than anticipated.

Appendix A: Membrane/Amine Hybrid Grissik Gas Plant

Gas chilling process and Regenerable adsorption process. Gas chilling process Deemed ineffective at the plant operating pressure, which was near the cricondenbar of the feed gas phase envelope Regenerable adsorption process Short cycle process from Engelhard which uses Sorbead (Silica Gel) as the adsorbent Uses multiple beds in parallel adsorption to remove Heavy hydrocarbons Aromatics Napthenes Adsorption cycle is followed by regeneration of the silica gel at elevated temperatures. TSA was built and installed by Kvaener in 2000

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Designed to reduce C6 components (including aromatics and napthenes) so that membrane performance can be maintained for an extended period of time Designed with two separate trains, each with four adsorption vessels (refer to Figure A-3)

TSA design and performance

General Design Considerations
Since feed gas was found to contain high levels of heavy hydrocarbons (C10, aromatics, and napthenes) TSA had two functions and solved two problems: TSA removes heavy hydrocarbons for proper pretreatment so as to yield long membrane life.

FIGURE A-3 Engelhard thermal swing adsorption unit.

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Removal of heavy hydrocarbons allows the sales gas to meet hydrocarbon dew point specs. treated gas to the downstream membrane unit. Balance of the feed gas bypasses the pressure drop valve so as to provide the necessary flow through the towers being cooled and heated. Regeneration path contains the Tower being cooled Regeneration heater Tower being heated Heat recovery heat exchangers, and Spent regeneration gas separator Each tower is associated with six valves that allow it to change functional positions Adsorbing Heating/regenerating Cooling Adsorbing Wet feed gas is used as the regeneration medium, and because of the pressure drop valve, there is no need for a compressor to boost the pressure of the spent regeneration gas.

Since water is more strongly held onto the Sorbead adsorbent than any of the hydrocarbons, the TSA system also dehydrates the feed upstream of the membrane unit.

TSA Process Description

Each train was designed to treat 225 MMscfd Consists of four internally insulated adsorber towers Minimize the thermal mass for the short thermal cycle Reduces heat load on the system Refer to TSA process flow diagram (Figure A-4) Feed gas, after passing through the two-phase separator, is split into two parallel paths. Majority of the gas flows through the pressure drop valve and then directly to two towers on parallel adsorption. Cycle time of the towers is staggered by 50% to allow for a continuous flow of

Wellhead Pressure drop valve Liquid TSA 2 towers adsorbing Heavy liquids removed To membrane skids

TSA tower cooling Regen heater

TSA tower heating

FIGURE A-4 TSA process flow diagram.

Appendix A: Membrane/Amine Hybrid Grissik Gas Plant

During adsorption Water and C6 components are adsorbed at 1100 psig and 90140  F. Prior to C6 breakthrough, the tower position is switched to heating mode and is completely heated to 540  F. Internal insulation allows heating of the adsorbent only and not the steel shell. During heating, the water vapor and C6 components are desorbed Spent regeneration gas stream containing water and C6 is then cooled and Condensed liquids removed in the regeneration gas separator. This is the only place in the process where the heavy hydrocarbons exit the system.

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Heating and cooling towers are in a series arrangement which also conserves the amount of regeneration gas required. Additional benefit of having towers in parallel on adsorption is an equalized composition of the treated gas. In a single tower system There is a difference in the gas composition between beginning and end cycle, caused by the breakout of the individual components. In a four tower system with two towers on adsorption There is an offset time of half an adsorption cycle. Gas composition of the combined outlet gas is more constant than from a single tower system.

Cycle Times and Breakthrough

Cycle times Driven by the breakthrough behavior of the C6 components in the tower design in order to meet the hydrocarbon specification of the treated gas Result of analysis and field observations Typical cycle consisted of (Refer to Table A-1) Two-hour adsorbing One-hour heating, and One-hour cooling.

Reasons for Four Towers

In order to maintain an acceptable flow velocity across the adsorber bed, the number of towers used is a function of Flow rate and Tower diameter. Maximum tower diameter was determined by transport limits; Grissik design resulted in four towers with two towers in parallel adsorption. Internal insulation was used to minimize the amount of regeneration gas requirement.

Heat Recovery Between Cooling and Heating

System uses one tower heating and one tower cooling at a time.

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Table A-1 Tower mode timing

Tower Tower Tower Tower 1 2 3 4 2h 1h 1h 1h Adsorption Cooling Heating Adsorption 1 h Heating 2 h Adsorption 1 h Cooling 1 h Heating 1h 1h 2h 1h Cooling Heating Adsorption Cooling, 1 h adsorption

Hot gas leaving the tower being cooled flows through the heater in order to get additional heat in. At the beginning of the cycle, gas exiting the tower on cooling is almost at the required heating temperature. Results in nearly no make-up heat being required Due to the entire tower being cooled the gas is at the hot regeneration temperature of 540  F During the cooling cycle, the temperature of the gas exiting the cooling tower Drops so the heater has to provide the required heating gas temperature. Gas-to-gas heat exchanger It is used to capture the heat exiting the tower which is being heated. Hot gas is cross-exchanged with the gas upstream of the regeneration gas heater (Refer to Figure A-4). Exchanger is bypassed during the time when the gas exiting the tower on cooling is at a higher temperature than the gas leaving the tower in the heating step. Regeneration heater Direct-fired heaters Size of the heater depends on the regeneration gas flow required to heat the

adsorption bed and desorb the water and hydrocarbons within the design cycle time. TSA performance After recommissioning the plant in October 2000 Good TSA performance removing the heavy hydrocarbons led to excellent membrane performance. TSA performance regarding hydrocarbon dew point was impressive, see Table A-2. Corresponding phase envelopes are shown in Figure A-5. Figure A-6 shows the results of gas sampling done with a mass spectrometer where both the feed and exit streams of the TSA were analyzed dynamically. Ratio of hydrocarbon concentration in the outlet versus inlet is shown. Note the strong cutoff that occurs between C6 and C8. Heavier hydrocarbons are essentially completely removed.

Table A-2 TSA hydrocarbon dew point

TSA feed gas TSA outlet gas 86  F at 1150 psig 22  F at 1115 psig

Appendix A: Membrane/Amine Hybrid Grissik Gas Plant

1600 1400 1200 Pressure [psig] 1000 800 600 400 200 0 250
Dew pt possible by chilling Bubble point Actual TSA outlet gas dew pt

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Actual TSA inlet gas dew pt

200

150

100 50 0 Temperature [F]

50

100

150

FIGURE A-5 TSA inlet and outlet phase envelopes.

1

TSA outlet/inlet

C4

C5

C6

C7

C8

C9

C10

C11

FIGURE A-6 TSA hydrocarbon tail.

Air liquidemedal membrane

General Considerations
Polyimide hollow fiber membrane elements (shown in Figure A-7) provide for a high efficiency separation of CO2 from hydrocarbon streams. Membrane system was fabricated as multiple skids (refer to Figure A-8) operating in parallel.

Each skid contains multiple horizontal tubes. Each tube contains multiple membrane elements (refer to Figure A-9). Multiple elements are installed in a single tube. Membrane elements are actually functioning in parallel. More than 100 membrane elements are used in this plant.

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C1+ CO2 H2S H2O C1+

Air liquide CO2 H2S H2O

FIGURE A-7 Air LiquideMEDAL natural gas membrane.

FIGURE A-8 Skid containing Air Liquide membrane elements.

Feed

Permeate

Residue

FIGURE A-9 Multiple membrane element flow arrangement.

Feed gas enters the tube near one end and flows axially to all the membrane elements by way of an annular clearance. Each element is composed of several hundred thousand parallel hollow polyimide fibers. Feed gas enters the membrane elements on the fiber shell inside and flows over the fibers, where CO2 is removed, to a coaxial tube in

Appendix A: Membrane/Amine Hybrid Grissik Gas Plant

the center of each element (retentate). Retentate streams for each element flow axially to exit at one end of the tube. CO2 selectively permeates into the bore of the fibers and then flows axially to a collection point at the end of each element (permeate). Permeate of each element is then collected in the coaxial center tube and flows axially to exit the tube at the opposite end from the retentate.

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Permeate pressure is about 10 psig which flows to the steam generator burners. Hydrocarbon losses versus time One of the major advantages of the polyimide membrane is its ability to maintain integrity indefinitely, even aging in the presence of heavy hydrocarbons. As shown in Figure A-10, membrane integrity is solid and the hydrocarbon losses have decreased somewhat since startup. This trend of decreasing hydrocarbon losses indicates no loss of membrane integrity and actually shows a slight increase in apparent intrinsic membrane selectivity. Such a selectivity increase would be consistent with the change in permeability (see below). Membrane capacity versus time After TSA was commissioned in October 2000

Membrane Performance
Typical operating conditions Membrane skids are fed directly from the output of the TSA. Feed temperatures vary between 90 and 120  F. Feed pressure is 1100 psig. Feed gas contained 30% CO2.

1.2

1.0
Hydrocarbon losses (normalized)

Design losses

0.8

0.6

0.4

0.2

0.0 Aug-00

Mar-01

Sep-01

Apr-02

Nov-02

FIGURE A-10 Membrane hydrocarbon losses versus time.

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One membrane skid was retrofitted with new membrane elements and its performance tracked. Results shown in Figure A-11 Vertical axis is labeled Relative Capacity to Remove Moles of CO2 which is the normalized intrinsic membrane permeability. Initial capacity was well above design, and after 10 years of operation, the capacity still remains above design. Exact membrane life can be extrapolated to be over 12 years without replacement Excellent operation of the TSA and membrane have resulted in years of trouble free operation with zero maintenance, that is, no membrane replacements. Membrane skids were shut down and restarted many times for maintenance of surrounding equipment or capacity turndown. Start and stop, or pressurization and depressurization cycles have no effect on membrane performance, although caution must be used to avoid reverse pressurization.

Permeate/Acid Gas Utilization

Two waste heat boiler units are installed. Waste heat boilers recover waste heat available in low BTU permeate gas stream (150250 Btu/scf) from the membrane units. Utilizing waste heat in the permeate stream means single stage membrane can

2.0 Relative capacity to remove moles of CO2

1.5

1.0

Design capacity

0.5

0.0 0 5000 10,000 15,000 20,000 Hours from start-up 25,000 30,000 35,000

FIGURE A-11 Membrane capacity versus time.

Appendix A: Membrane/Amine Hybrid Grissik Gas Plant

be used without the limitations of a second membrane stage with the accompanying recycle gas compressor and still avoid hydrocarbon losses. Boilers are designed to incinerate the acid gases removed by the amine unit. Auxiliary fuel is utilized to make up any inadequacy of heating value input and to stabilize the flame. Furnace temperature is maintained above 1600  F prior to introducing permeate fuel or acid gases. Lower temperature leads to incomplete destruction of the component and results in the emission hazards. Waste heat boilers are controlled by steam header that actuates pressure control valves on each steam drum. Output of the steam header pressure controller goes through flow ratio controllers of permeate gas, fuel gas, and combustion air. Fuel gas flow rate is set around 10% of permeate gas flow rate while combustion air is controlled to ensure stoichiometry and complete combustion with 25% excess air. Waste heat boiler produces steam up to 210,000 lbs/h at 150 psig and 348  F. Biggest consumer of steam produced is the amine system. Condensing heat released by the steam is used to remove acid gas from amine solvent at amine reboilers.

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Amine System
Amine system further reduces CO2 and H2S to meet sales gas specification. Residue gas from the membrane unit, containing 15% CO2, Flows into the amine contactors and Contacted with lean amine (50%wt-activated MDEA). CO2 absorption by activated MDEA is limited to a maximum loading of 0.5 mol acid gas/mol MDEA. CO2 content in the treated gas varies between 2% and 5% by volume (3%-vol average). Rich amine is then flashed at 75 psig, heated through a lean/rich amine exchanger, and regenerated by the steam heated reboiler. The 150 psig steam used for regenerating amine is produced in the waste heat boiler that burns permeate gas. Several common problems of an amine system include Reduced strength and ability to absorb acid gas Degradation Foaming and CO2 corrosion attack during acid gas breakout inside the reboiler. Most problems found in an amine system are due to the presence of contaminant in the amine solvent, including Heat stable salts Degradation products Injected chemicals Hydrocarbons and Particulates. Heat stable salts and degradation products are formed by amine

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Treated gas condition at the outlet of the amine unit is normally 3%-vol CO2 and 24 ppmv H2S, while sales gas contract specifies 5%-vol CO2 and 8 ppmv H2S. One advantage from the high performance of absorption is an allowance to increase system deliverability by bypassing some untreated gas and blending with treated gas while maintaining the sales gas specification.

solvents that decompose and/or react with other contaminants. TSA/membrane installed upstream of the amine system has mitigated the above problems to an acceptable level. TSA unit removes heavy hydrocarbons from the feed gas and nearly eliminated the foaming risk of amine solvent. An antifoam injection system is provided to anticipate worst case conditions. CO2 content reduction by the membrane unit Breakout in the regeneration process Lessons CO2 breakout in the regeneration process Reduces contaminants that may trigger salt formation or amine degradation Though contaminants could also be introduced by makeup water or even makeup amine

References
1. Anderson, C.L. and Siahaan, A. Case study: Membrane CO2 removal from natural gas, Grissik gas plant, Sumatra, Indonesia, Regional Symposium on Membrane Science and Technology, 2004, Johor Bahru, Malaysia. 2. Malcolm, J. The Grissik gas plant, Hydrocarbon Asia, 2001. 3. Anderson, C.L. Case study: Membrane CO2 removal from natural gas, Regional Symposium on Membrane Science and Technology, 2004, Johor Bahru, Malaysia.