Instructor: Dr. Istadi ( )

Transcription

1 Instructor: Dr. Istadi ( ) istadi@undip.ac.id

2 Course Syllabus: (Part 1) 1. Definitions of Natural Gas, Gas Reservoir, Gas Drilling and Gas production (Pengertian gas alam, gas reservoir, gas drilling, dan produksi gas) 2. Overview of Gas Plant Processing (Overview Sistem Pemrosesan Gas) and Gas Field Operations and Inlet Receiving (Operasi Lapangan Gas dan Penerimaan Inlet) 3. Gas Treating: Chemical Treatments (Pengolahan Gas: secara kimia) and Sour Gas Treating (Pengolahan Gas Asam) 4. Gas Treating: Physical Treatments (Pengolahan Gas: secara fisika) 5. Gas Dehydration (Dehidrasi Gas) 6. Gas Dehydration (Dehidrasi Gas) 7. Hydrocarbons Recovery (Pengambilan Hidrokarbon)

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4 PHYSICAL ABSORPTION! Absorption processes are generally most efficient when the partial pressures of the acid gases are relatively high, because partial pressure is the driving force for the absorption.! Heavy hydrocarbons are strongly absorbed by the solvents used, and consequently acid gas removal is most efficient in natural gases with low concentrations of heavier hydrocarbons.! Solvents can be chosen for selective removal of sulfur compounds, which allows CO 2 to be slipped into the residue gas stream and reduce separation costs.! Energy requirements for regeneration of the solvent are lower than in systems that involve chemical reactions.

5 ! Separation can be carried out at near-ambient temperature.! Partial processes produce a water saturated product stream that must be dried in most applications.! Organic liquid (solvents) are used in these processes to absorb H 2 S (usually) preferentially over CO 2 at high pressure and low temperatures.! Regeneration is carried out by releasing the pressure to the atmosphere and sometimes in vacuum with no heat.

6 Proper>es of Physical Solvents

7 SELEXOL PROCESS! Selexol is a typical application of physical absorption that uses a mixture of dimethyl ether and propylene glycols as a solvent.! A cool stream of natural gas is injected in the bottom of the absorption tower operated at 1000 psia.! The rich solvent is flashed in a high flash drum at 200 psia, where methane is flashed and recycled back to the absorber and joins the sweet gas stream.! The solvent is then flashed at atmospheric pressure and acid gases are flashed off.

8 Selexol! The solvent is then stripped by steam to completely regenerate the solvent, which is recycled back to the absorber; any hydrocarbons will be condensed and any remaining acid gases will be flashed from the condenser drum.! This process is used when there is a high acid gas partial pressure and no heavy hydrocarbons.! DIPA (di- isopropanol amine) can be added to this solvent to remove CO2 down to pipeline specifications

9 Selexol Process Schema>c

10 K- Value K i = P i sat /P y i.p = x i. P i sat! R k Value = K-value methane / K-value component! The K-value is the ratio of the mole fraction of the component in the vapor phase (y) to its mole fraction in the liquid phase (x), K = y/x.! High K-values indicate the material is predominately in the vapor phase, whereas low K-values indicate a higher concentration in the liquid phase (x).

11 R k Value - Selexol! An R k value greater than unity indicates the solubility of the component in Selexol is greater than that of methane, whereas a value less than unity indicates the opposite! Because R K for CO 2 and H 2 S are 15 and 134, respectively, these gases are preferentially absorbed (relative to CH 4 ), and, consequently, physical absorption is an effective technique for acid gas removal.! The process can reduce H 2 S to 4 ppmv, reduce CO 2 to levels below 50 ppmv, and essentially remove all mercaptans, CS2, and COS.! R K values for hydrocarbons heavier than CH4 are fairly high (6.4 for C2H6, 15.3 for C3H8, and 35 for n- C4H10), Selexol will remove substantial quantities of these hydrocarbons, a feature that can be either positive or negative, depending on the composition of the gas being processed and the desired products.! Finally, the R K value of H2O is extremely high and consequently, Selexol provides some dehydration

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13 Solubility of various gases in Selexol solvent at 70 F (21 C) as a func>on of par>al pressure! For an ideal system, Henry s law assumes a linear relation between the solubility of gas component i and its partial pressure,! y i.p = H i.x i! where H i is the Henry s constant.

14 HENRY S LAW! P i = H.X i or X i = (Y i / H).P! This implies that acid gas absorbed in liquid phase (X i ) is proportional to its gas mole fraction (Y i ) and inversely to Henry s constant (which is constant for a given temperature).! Much more importantly, the solubility is proportional to the total gas pressure (P).! This means that at high pressure, acid gases will dissolve in solvents, and as the pressure is released, the solvent can be regenerated.

15 Example: Composi>on of Inlet and Outlet Gas in a Selexol Unit

16 FLUOR PROCESS! This process uses propylene carbonate to remove CO 2, H 2 S, C 2+, COS, CS 2, and H 2 O from natural gas.! Thus, in one step, the natural gas can be sweetened and dehydrated.

17 Purisol Process! This process uses N-methyl-2-pyrrolidone also known as NMP as a solvent (licensed by Lurgi).! The solvent removes H 2 S, CO 2, H2O, RSH, and hydrocarbons and elastomers.! The feature of this solvent is that it is highly selective for H 2 S.! It has a boiling point of 396 o F, which is rather low to be used in amine mixed solvents.! Regeneration is accomplished by two strippers, where dissolved hydrocarbons are stripped off as fuel gas nitrogen in the first drum! and acid gases are stripped in the second stripper;! regenerated NMP is recycled back to the absorber.

18 Purisol Process Scheme

19 Sulfinol/Claus Process! This process uses a solvent which is 40% sulfolane (tetrahydrothiophene 1-1 dioxide), 40% DIPA (di-isopropanolamine), and 20% water.! Enhancing amine selectivity by adding a physical solvent such as sulfolane. Sulfolane is an excellent solvent of sulfur compounds such as H 2 S, COS, and CS 2. Aromatics, heavy hydrocarbons, and CO 2 are soluble to a lesser extent.! Sulfinol is usually used for H 2 S/CO 2 ratios greater than 1:1 or where CO 2 removal is not required to the same extent as H 2 S.! The sour gas components are removed from the feed gas by countercurrent contact with a lean solvent stream under pressure.! The absorbed impurities are then removed from the rich solvent by stripping with steam in a heated regenerator column.! The hot lean solvent is then cooled for reuse in the absorber absorber. Part of the cooling may be by heat exchange with the rich solvent for partial recovery of heat energy.

20 Sulfinol/Claus Process

21 Comparison of Physical Solvents! Purisol has the highest capacity for absorption of acid gases and it is the most selective; however, it is the most volatile.! Selexol is more selective than Fluor solvent, but it dissolves propane.! All solvents exhibit significant affinity for heavy paraffins, aromatics, and water.! Water absorption make them good dessicants.! The loading capacity of physical solvent is much higher than amines.! From Figure: At partial pressure of H 2 S 200 psia, the loading (mol H 2 S/gal solvent) of MEA (20% solution) is about 11.5, and at the same time, sulfolane (physical solvent) is about 18 and sulfinol (which is a mixed solvent) is about 19.

22 Equilibrium solvent loadings

23 HYBRID PROCESSES! The strengths and weaknesses of amine and physical solvent system! To take advantage of the strengths of each type, a number of hybrid processes commercially used, and under development, combine physical solvents with amines! Depending upon the solvent amine combination, nearly complete removal of H 2 S, CO 2, and COS is possible! Sulfinol : The process uses a combination of a physical solvent (sulfolane) with DIPA or MDEA.! Like the physical solvent processes, the hybrid systems may absorb more hydrocarbons, including BTEX, but that property can be adjusted by varying water content.

24 ADSORPTION! Acid gases, as well as water, can be effectively removed by physical adsorption on synthetic zeolites! Applications are limited because water displaces acid gases on the adsorbent bed! From typical isotherms for CO 2 and H 2 S on molecular sieve, indicates that at ambient temperatures substantial quantities of both gases are adsorbed even at low partial pressures! Molecular sieve can reduce H 2 S levels to the 0.25 gr/ 100 scf (6 mg/m 3 ) specification.! However, this reduction requires regeneration of the bed at 600 F (315 C) for extended time?????

25 Schema>c of integrated natural gas desulfuriza>on plant! Dashed line denotes regeneration gas stream.

26 CRYOGENIC FRACTIONATION! Distillation! the most widely used process to separate liquid mixtures! It seems a good prospect for removing CO2 and H2S from natural gas, because the vapor pressures of the principal components are different! However, problems are associated with the separation of CO2 from methane, CO2 from ethane, and CO2 from H2S

27 Difference of Vapor Pressures

28 Dis>lla>on: CO 2 from methane! Relative volatilities (K C1 /K CO2 ) at typical distillation conditions are about 5 to 1. Therefore one would expect simple fractionation to work.! However, because the liquid CO2 phase freezes when it becomes concentrated, the practical maximum- vapor concentration of methane is only 85 to 90 mol %.

29 Dis>lla>on: CO 2 from ethane! In addition to solidification problems, CO2 and ethane form an azeotrope (liquid and vapor compositions are equal) and! consequently, complete separation of these two by simple distillation is impossible

30 Dis>lla>on: CO 2 from H 2 S! The distillation is difficult! The mixture forms a pinch at high CO2 concentrations.! This separation by conventional distillation is complicated by the need to have an overhead product that has roughly 100 ppmv H2S if the stream is vented.! The bottoms product should contain less than two- thirds CO2, assuming the stream is feed to a Claus unit.

31 Membrane Separa>on! Membranes are used in natural gas processing for dehydration, fuel-gas conditioning, and bulk CO 2 removal, but presently CO 2 removal is by far the most important application! Polymeric membranes separate gases by selective permeation of gas species in these membranes.! The gas dissolves at the contact surface of the membrane and permeate across the membrane under the partial pressure gradient across the membrane wall.! The basic idea of the process is to flow sour gas on one side of the membrane where only acid gases diffuse across the membrane to the permeate side and the rest of the gas exits as sweet gas

32 Rate of Permea>on! The rate of permeation of gas A(q A ) can be expressed as:! where PM is the gas permeability in the membrane, A m and t are the surface area and thickness of the membrane, respectively, and P A is the partial pressure of gas A across the membrane.

33 CARBON DIOXIDE REMOVAL FROM NATURAL GAS! For CO2 removal, the industry standard is presently cellulose acetate.! These membranes are of the solution- diffusion type, in which a thin layer (0.1 to 0.5 μm) of cellulose acetate is on top of a thicker layer of a porous support material.! Permeable compounds dissolve into the membrane, diffuse across it, and then travel through the inactive support material.! The membranes are thin to maximize mass transfer and, thus, minimize surface area and cost, so the support layer is necessary to provide the needed mechanical strength.

34 Hollow Fiber Membrane

35 Spiral Wound Membrane

36 Gas flow paths for spiral- wound module

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38 Single Stage CO 2 /CH 4 Membrane Separa>on

39 Two- stage Membrane process

40 Feed Gas Pretreatment! Because membranes are susceptible to degradation from impurities, pretreatment is usually required.! The impurities possibly present in natural gas that may cause damage to the membrane

41 ADVANTAGES OF MEMBRANE SYSTEMS! Low capital investment when compared with solvent systems! Ease of installation: Units are normally skid mounted! Simplicity: No moving parts for single- stage units! High turndown: The modular nature of the system means very high turndown ratios can be achieved! High reliability and on- stream time! No chemicals needed! Good weight and space efficiency! Ease of operation: process can run unattended

42 DISADVANTAGES OF MEMBRANE SYSTEMS! Economy of scale: Because of their modular nature, they offer little economy of scale! Clean feed: Pretreatment of the feed to the membrane to remove particulates and liquids is generally required! Gas compression: Because pressure difference is the driving force for membrane separation, considerable recompression may be required for either or both the residue and permeate streams! For natural gas:! Generally higher hydrocarbon losses than solvent systems! H2S removal: H2S and CO2 permeation rates are roughly the same, so H2S specifications may be difficult to meet! Bulk removal: Best for bulk removal of acid gases; membranes alone cannot be used to meet ppmv specifications

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