Instructor s t Background

Transcription

1 Teknologi Pemrosesan Gas (TKK 564) Instructor: Dr. Istadi ( ) il iistadi@undip.ac.id di di id

2 Instructor s t Background BEng. (1995): Universitas Diponegoro Meng. (2000): Institut Teknologi Bandung PhD. (2006): Universiti Teknologi Malaysia Specialization: Catalyst Design for Energy Conversion Process Design for Energy Conversion Combustion Engineering Computational Fluid Dynamic (CFD)

3 Course Syllabus: (Part 2) 1. Hydrocarbons Recovery (Pengambilan Kembali Hidrokarbon) 2. Nitrogen Rejection/Removal (Penghilangang g Nitrogen) ) 3. Trace Component Removal (Penghilangan Komponen lainnya) 4. Natural Gas Liquid Processing and Sulfur Recovery (Pemrosesan Cairan Gas Alam dan Penghilangan Sulfur) 5. Gas Transportation and Storage (Transportasi dan Penyimpanan Gas) 6. Liquified Natural Gas #1 (Gas Alam Cair) 7. Liquified Natural Gas #2 (Gas Alam Cair) 8. Second Assignment 9. Ujian Akhir Semester

4

5 This chapter discusses processing the hydrocarbon liquids Liquid stream proceed in a glass plan Condensate processing NGL processing

6 CONDENSATE PROCESSING

7 Two steps of Condensate Processing Water washing to remove salt and additives Condensate stabilization remaining lighter hydrocarbons are stripped and recombined with the gas that leaves the inlet receiver to produce a bottom product that has specifications to be sold as natural gasoline or slop oil

8 Sweetening for Liquid Processing Ideally, the sulfur compounds go with the light gases stripped in the stabilizer, so that they can be removed ed in gas treating. Most of the H2S and CO2 will be removed along with COS, CS2, and mercaptans. To enhance acid gas removal, sweet natural gas can be used as a stripping gas. This process can reduce H2S levels to the 10 ppmv range. However, the cost is increased recycle compression. If the natural gasoline is sour, the plant can either treat it or take a price penalty and sell the liquid as sour crude. The price differential between sweet and sour crude drives the need for sweetening. In many cases, the liquid volumes are low and sweetening at the plant is not justified.

9 NGL Processsing

10 Sweetening Method in NGL Processing Amine Treating Most remove only CO2 and H2S. Two amines, DGA and DIPA, will remove COS, but none remove CS2 and merchaptans. Amine treating is often used upstream of caustic treaters to minimize caustic consumption caused by irreversible reactions with CO2. Adsorption Able to remove sulfur compounds down to low levels when no water is present, which makes it attractive for treating demethanizer bottoms. Either promoted alumina, 13X or 5A molecular sieve will remove H2S, COS, and mercaptans from LPG. The larger pore 13X is usually preferred because it has a higher capacity Caustic Treating Regenerative = sodium hydroxide. Nonregenerative = ZnO, KOH

11 Regenerative caustic wash and water wash.

12 Chemistry involved in Washing Air is added to the rich caustic, with a catalyst to oxidize the mercaptan to a disulfide: 2RSNa + 1/2 O2 + H2O RSSR + 2NaOH

13 Dehydration Process in NGL Adsorption Processes Desiccant Dehydration Gas Stripping Distillation Absorption

14

15 Currently only two methods are available for dealing with large quantities of H2S: 1. Disposal of the gas by injection into underground formations 2. Conversion of the H2S into a usable product, elemental sulfur

16 Properties of Sulfur

17 SULFUR RECOVERY PROCESSES 1. Claus Process All Claus units involve an initial combustion step in a furnace. The combustion products then pass through a series of catalytic converters, each of which produces elemental sulfur.

18 Basic Process H2S + 3/2 O2 H2O + SO2 2H2S+SO2 2 H2O + (3/x) Sx The first reaction is a highlyhl exothermic combustion reaction, whereas the second is a more weakly exothermic reaction promoted by a catalyst to reach equilibrium. KohlandNielsen(1997)pointoutthatatasulfurpartial pressure of 0.7 psia (0.05 bar) and temperaturest bl below 700 F (370 C), the vapor is mostly S6 and S8, but at the same partial pressure and temperatures over approximately 1,000 F (540 C), S2 predominates.

19

20

21 Process

22 2. CLAUS TAIL GAS CLEANUP Before sulfur emissions restrictions were imposed, the offgas from the Claus unit was flared to convert the remaining H2S to SO2. Now, environmental agencies demand higher sulfur recovery than can be achieved with a standard Claus unit, and additional treating of the Claus tail gas is needed. The tail gas cleanup entails either an add-on at the end of the Claus unit or amodification of the Claus unit itself.

23 three categories for final sulfur removal (Kohl and Nielsen, 1997): Direct oxidation of H2S to sulfur Sub-dew point Claus processes SO2 reduction and recovery of H2S

24 Direct Oxidation of H2S to Sulfur Catalytic Reaction : 2H2S + O2 2S + 2H2O The selective oxidation catalyst in the third reactor does not promote the reaction 2H2S + 3O2 2SO2 + 2H2O or the reverse reaction of sulfur with H2O 3S + 2H2O 2H2S + SO2 Total revovery rate = 99%

25 Sub Dew Point Claus Processes

26 SO2 reduction and recovery of H2S

27 Sulfur Storage Sulfur from the Claus unit is withdrawn as a liquid and is generally stored and transported in the molten state. A number of potential problems are associated with sulfur storage, including release of H2S dissolved in the molten sulfur and the possibility of sulfur fires, which will produce highly toxic SO2. Sulfur fires. Uncommon, but they can produce large amounts of SO2. H2S. Any H2S dissolved in the molten sulfur from the condensers may be a significant hazard if appropriate p degassing g techniques are not used. Corrosion. A wet sulfidic atmosphere can lead to severe corrosion of carbon steel. SO2. Highly toxic and it forms highly corrosive sulfurous acid in the presence of water. Static discharge. Because of the excellent insulating properties of molten sulphur, static discharge may occur under certain conditions and lead to possible fires or explosions.

28

29

30

31