Comparison of the biogas upgrading methods as a transportation fuel

Accepted Manuscript Comparison of the biogas upgrading methods as a transportation fuel

Sayed Amir Hosseinipour, Mehdi Mehrpooya PII:

S0960-1481(18)30741-9

DOI:

10.1016/j.renene.2018.06.089

Reference:

RENE 10245

To appear in:

Renewable Energy

Received Date:

27 November 2017

Accepted Date:

21 June 2018

Please cite this article as: Sayed Amir Hosseinipour, Mehdi Mehrpooya, Comparison of the biogas upgrading methods as a transportation fuel, Renewable Energy (2018), doi: 10.1016/j.renene. 2018.06.089

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ACCEPTED MANUSCRIPT

Cryogenic separation method

Amine scrubbing method

Water scrubbing method

Caustic wash method

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Comparison of the biogas upgrading methods as a transportation fuel

2 3 4 5 6 7 8

Energies and Environmental Department, Faculty of New Science and Technologies, University of Tehran, Tehran, Iran ************************************************************************************

9

The aim of this study is investigating and analyzing the water scrubbing, cryogenic separation,

10

amine scrubbing and caustic wash biogas upgrading processes. In order to comparing the

11

upgrading processes, input condition is supposed to be fixed for all of the processes. The results

12

of this study indicate that although amine scrubbing process consumes less power but the required

13

hot utility is higher than other upgrading methods. In the cryogenic process, high pressure

14

operating condition needs high compression power. This process also needs low temperature

15

refrigeration system. Water wash process is a simple and economic method which has acceptable

16

separation efficiency, but caustic wash is more efficient than other methods and its energy

17

consumption is reasonable.

Sayed Amir Hosseinipour1, Mehdi Mehrpooya1 1Renewable

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Keywords: Biogas upgrading methods; Cryogenic separation; Water scrubbing; Amine

20

scrubbing; Caustic wash

21 22 23 24

Corresponding

Author: Email address: [email protected] (M. Mehrpooya)

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1. Introduction

27

The concept of using carious vegetable for producing a flammable gas has been understood since

28

the ancient Persians [1]. In recent centuries, the first sewage plant was built in Bombay in 1859

29

[2]. This is idea reached to England in 1895 when biogas was recovered from a "carefully

30

designed" sewage treatment facility, and the produced gas was used to light street lamps [3]. The

31

treatment of sewage was developed in the UK and Germany in early 1900s . At the same time

32

with development of microbiology as a science, Buswell and others [4] in 1930s identified

33

anaerobic bacteria and promote conditions of methane production.. The produced gas was

34

occasionally used as a source of energy. Prasertsan [5] shows produced biogas can be used

35

through cogeneration of electricity and heat production in CHP plants or it can be upgraded to

36

natural gas standards and replacing with it. With the exception of direct combustion in boilers or

37

burners, gas engines are usually employed as shaft force in biogas utilization. Tippayawong et al

38

[6] points to the greater potential of biogas. It can be made viable alternative for natural gas as a

39

transport vehicle fuel. Biogas was considered as one the renewable sources for providing the

40

required heat load in greenhouses[7]. The experimental results show that it can be used

41

satisfactorily as a heat source. Raw biogas contains impurities such as carbon dioxide and

42

hydrogen sulfide and it’s HHV level is lower than the natural gas. Different processes have been

43

proposed for sweetening of raw biogas. Tippayawong et al [8] also believe that biogas can be

44

available everywhere, via storing biogas in the compressed cylinders, or translocate it by

45

pipelines. But this is reachable only after omitting CO2, H2S and other impurities. In the biogas

46

quantity of CO2 is high and significant. Its presence therefore decreases heat value of the biogas.

47

The share of CH4 will be increased in biogas if CO2 and other impurities are removed [9]. Another 2

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contaminant in biogas is H2S, its removal is essential before any eventual utilization of biogas,

49

because this contaminant is highly undesirable in combustion systems due to its conversion to

50

highly corrosive and environmentally hazardous compounds [10].

51

Composition of the generated biogas depends on type of the inlet feed, production site, climatic

52

conditions and type of the used technology [11]. Methane content of the biogas varies between

53

50% and 75%. Share of carbon dioxide (CO2) is between 25% and 50%, and content of hydrogen

54

sulphide (H2S) can vary from 100 to 10,000 ppm [12]. Presence of these impurities in biogas

55

affect engine performance adversely. Reducing CO2 and H2S content improves the biogas quality.

56

If biogas is upgraded to bio-methane with approximately 98% methane in a biogas treatment

57

plant, the bio-methane has the same properties as natural gas[13]. Several different commercial

58

methods are available for biogas upgrading; these include absorption by chemical solvents,

59

physical absorption, cryogenic separation, membrane separation and biological fixation or

60

chemical methods [14]. Different kinds of chemical processes have been used for biogas

61

upgrading. Conventional analysis and optimization tools can be applied for evaluation of under

62

consideration chemical processes. Techno-economic & cost analysis [15, 16], energy and exergy

63

analysis [17, 18], optimization of the operating condition[19] are some of the most conventional

64

reported methods.

65

In this study conventional upgrading methods including cryogenic separation, water wash, amine

66

scrubbing and caustic wash with NaOH are simulated and compared to show which method is

67

more efficient and useful.

68

1.1. Water scrubbing method

69

Water scrubbing is the most commonly method for biogas purification. It works based on the

70

physical properties of dissolving gases in the water [20]. This method can be used to absorb CO2 3

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and H2S from biogas since solubility of these components in water is more than methane [13]. In

72

high pressure water scrubbing, gas enters from bottom of the high pressure column. Then, water

73

is sprayed from the top of the column so that it flows down counter-current to the gas. To ensure

74

a high transfer area for gas liquid contact, the column can be filled with packing material or using

75

trayed columns instead. By using this process, the obtained methane purity can reach more than

76

96% [21]. It was tried to optimize the essential parameters of a pilot-scale countercurrent

77

absorption process for upgrading landfill gas to produce vehicle fuel and showed 99% impurities

78

can be removed from the raw biogas. It is distinct advantage that chemicals are not required during

79

entire process. Starr K and et al [22] mentioned that the only disadvantage of the system is that

80

a lot of water required even with regeneration. This study evaluates and compares the life cycle

81

assessment of three biogas upgrading technologies. Such as a high pressure water scrubbing

82

(HPWS), alkaline with regeneration (AWR) and bottom ash upgrading (BABIU).

83

1.2. Cryogenic separation method

84

The basis of the separation is difference in physical and chemical properties of the substances.

85

Techniques used to separate mixtures rely on differences in the physical properties (BP, DP, etc.)

86

of the components [23]. The major aim of this research is to evaluate energy balances for

87

production of liquid biogas(LBG), and shows LBG is more energy intensive than the production

88

of compressed biogas. For example boiling point of methane (CH4) and carbon dioxide at

89

atmospheric pressure are −160 °C (CO2) is −78 °C respectively [24]. In this study a review of

90

fundamentals of biogas cleaning and upgrading methods is done. Cryogenic separation is a

91

distillation based process that demands cryogenic temperature, low temperatures close to -125°C,

92

and high pressure, approximately 50 bar. Because CO2, CH4 and other biogas compositions

93

liquefy at different pressures and temperatures, it is possible to produce pure CH4 from the biogas.

4

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In order to liquefy CO2 from crude biogas it must be cooled and compressed simultaneously [23].

95

The extracted CO2 can also be used as a solvent to remove impurities from the gas [25]. This

96

study discusses about simulation of CO2 removal from natural gas by low-temperature distillation

97

and shows how to decrease amount of CO2 from 50.6 vol-% to LNG specification (50 ppm).

98 99

1.3. Amine scrubbing method

100

Treating gas via amine also known as gas sweetening, amine scrubbing and acid gas removal

101

refers to a type of processes that uses aqueous solutions of various alkyl-amines family to remove

102

impurities such as carbon dioxide (CO2) and hydrogen sulfide (H2S) from gases [26]. This review

103

paper discusses about different methods of biogas cleaning and they differ in operating conditions

104

and functioning, specifications of the raw biogas, and efficiency. Amine scrubbing, is a chemical

105

absorption method, meaning that CO2 and H2S are chemically bound to an organic scrubbing

106

agent [13] Different alkanolamine solutions and ethanolamine–water mixtures can be used for

107

separation of CO2 in chemical absorption processes as absorption agents. Some of the most often

108

agents used for biogas upgrading are monoethanolamine (MEA), diethanolamine (DEA) and

109

methyldiethanolamine (MDEA), diisopropanolamine (DIPA), and aminoethoxyethanol (DGA).

110

Alkanolamines are widely used as absorbents for CO2 capturing [27]. CO2 loading capacity of

111

tertiary amine is higher than those of primary and secondary amines where the loading capacity

112

lies between 0.5 and 1.0 mole of CO2 per mole of amine [28]. In this paper methods of H2S and

113

CO2 removal from biogas by amine family is discussed. The reactions are as follows:

114

RR´NH + CO2 ---------- RR´NH+ COO-

(1)

115

RR´NH+ COO- + RR´NH ----------- RR’NCOO- + RR’NH2+

(2)

116 117

The overall reaction is defined as follows: 2RR´NH + CO2-------------- RR’NCOO- + RR’NH2+ 5

(3)

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RR’NCOO- + H2O ----------- RR´NH + HCO3-

(4)

119

Typical methane concentration in the purified gas is more than 95%[29]. Significant amounts of

120

N2 in the raw gas decreases product gas heating value because N2 cannot be absorbed in the

121

process, but this effect is found with in other upgrading methods as well. Furthermore, the entry

122

of O2 should be avoided because it can create unwanted reactions and degradation of the amine

123

solution [11]. This paper compares and discuss about major and commonly upgrading

124

technologies used in world and concludes that the cleaning and upgrading technologies which are

125

commercially available in the energy markets are water scrubbing, pressure swing adsorption,

126

and amine scrubbing. The raw gas contacts with the amine solution in the absorption column. The

127

advantages of amine absorption are low pressure requiring and high efficient removal of H2S [30].

128

Modelling of the carbon dioxide absorption by N-methyldiethanolamine (MDEA) and mono-

129

ethanolamine (MEA), experimentally examined under various operating conditions and the

130

results shows MDEA is better than MEA because of higher efficiency and easier regeneration.

131

Disadvantages are additional chemical substance requirement and waste chemical treatment is

132

also needed because of chemical hazards and high energy consumption in regeneration [31]. The

133

main aim of this paper is investigation of energy efficiency of amine absorption processes and

134

effects of changing rebioler heat duty and number of stages. Stabilization of amine-containing

135

CO2 adsorbents and dramatic effect of water vapor is investigated [32].

136

1.4. Caustic wash method

137

Caustic (NaOH) scrubbing (Caustic wash) systems can be used to treat biogas streams to remove

138

CO2 and H2S. This process uses countercurrent contacting of the gas stream with a caustic solution

139

in a packed or trayed column [33]. The column may contain one stage or several stages depending

140

on the required degree of removal [34], this book is about essentials of oil and gas utilities and in

6

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chapter three discusses about fresh and spent caustic units and chemical injection systems. The

142

used solution is either regenerated or discarded depending on inlet acid gas composition. If only

143

mercaptans would be present, the caustic solution is regenerated with steam in a stripping still. If

144

CO2 would be present, a non-regenerable product (Na2CO3) is formed and the solution must be

145

discarded [35]. As a result, the presence of CO2 in caustic systems leads to high caustic

146

consumption. This is a serious disadvantage of the caustic scrubbing process. The used caustic

147

solutions are considered hazardous wastes [36]. Bekkering et al [37] , Ryckebosch et al [26],

148

Adriana et al [38], Muñoz et al [39] and Angelidaki et al[40] published review papers for biogas

149

upgrading methods and techniques. Table 1 presents the summarization and comparison of these

150

studies.

151

Table 1.

152

2. Methodology

153

In this section basis of the modeling and simulation of under consideration upgrading processes

154

are explained.

155 156

1.5. Equipment design of the process

157

Steady state condition is assumed for simulation of the processes. Absorption columns, heat

158

exchangers, compressors, gas turbines, and pumps are the main equipment of the biogas

159

upgrading process. Logarithmic mean temperature difference (LMTD) method is considered for

160

temperature difference calculations in the heat exchangers. Designing of the equipment is done

161

by implementation of physical conditions and inputs data. The simulation procedure of the

162

process is done by fittingly combining the information about the equipment of the process. This

163

procedure is affected by linking the variables which are the output from one equipment and are 7

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used as the input in other equipment. The volume of a packed absorption towers also depends on

165

amount of gas and liquid flow rate, their properties, magnitude of the desired concentration

166

changes and rate of the mass transfer per unit. Most of the times absorption columns are operated

167

under pressure to give higher rank of mass transfer and more capacity. The solute’s equilibrium

168

partial pressure depends only on the liquid composition and the temperature [41] .

169

So overall material balances of the column are as follows[41]:

170

Total material:

La+ Vb = Lb + Va

(1)

171

Component A:

Laxa + Vbyb = Lbxb + Vaya

(2)

172

Relationship between x and y at any point is:

173

𝐿

y=𝑉 +

Vaya ‒ Laxa 𝑉

(3)

174

Where V is molar flow rate of the gas phase and L is liquid phase at the same point. The phase

175

concentration x, y applies to L-phase and V-phase.

176

Height of the tower can be calculated by equation ( 4 ) ;

177 178

𝑉/𝑆

𝑏 ZT = 𝐾 𝑎∫𝑎 𝑦

𝑑𝑦 𝑦‒𝑦

(4)

∗

Table 2 presents the main equations of the process equipment.

179

Table 2.

180

In this study 20 kgmole/hr of raw biogas at 2bar and 25 °C is considered as the inlet feed for all

181

upgrading methods (Table 3). In order to equalization the operating conditions of all processes,

182

and to measure the electrical consumption and the thermal energy requirements for heating and

183

cooling, all of the inlet streams containing gas are considered at 25℃ and 2 bar. And all of the

184

inlet streams containing liquid are considered at 25℃ and 1 bar. Should there be any changes in

185

above mentioned stream’s temperature and or pressure their energy requirements are calculated

186

and then simulated via software. Water scrubbing, cryogenic separation, amine scrubbing and 8

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187

caustic wash are the methods which have been simulated via Aspen Plus, Aspen HYSIS and also

188

Promax. The purpose of simulations is reaching to the highest concentration of methane in the

189

output biogas stream. All of the operating conditions has been designed the way that purity of the

190

biogas to be maximized. After reaching the highest concentration in the final upgraded biogas,

191

electricity consumptions, the required hot/cold utility and roles of operating parameters of the

192

process performance are discussed. Table 3.

193 194

2.1. Water scrubbing method

195

Due to Figure 1, stream 1, raw biogas with the mentioned condition enters a separator for

196

eliminating some physical or insoluble components. Next raw biogas, stream 2, is sent to

197

compressors and its pressure increases from 2 bar to 8 bar in two stages. Pressurized biogas

198

temperature decreases in air coolers, then stream 7 (8 bar, 10 °C) enters from bottom of the

199

absorption column. High pressure water, stream 17, enters from top of the absorption column.

200

Upgraded biogas, stream 8, is rich of methane and exits from top of the column. For water

201

regeneration, stream 9 enters a flash drum for omitting some of impurities from water, then stream

202

11 (8bar, 10.7 °C) follows to top of the regeneration column while high pressure air enters from

203

bottom of the column and interact with water and breaks physical bounds of the solved gases in

204

water, so after breaking the bounds, dissolved gases, exit from top of the regeneration column

205

with air. Regenerated water (8bar, 10 °C) is recycled to absorption column for reusing. Table 4

206

presents specifications of the main process streams. Table 5 shows details of water scrubbing

207

process equipment.

208

Table 4.

209

Table 5. 9

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Figure 1.

210 211 212

2.2. Cryogenic separation method

213

Due to Figure 2, stream 1 enters a three stage compressor while cooling via three air coolers in

214

order to decreasing temperature of the compressed gas. Table 6 presents specifications of the main

215

process streams. Table 7 shows details of the compressors and coolers. After increasing the

216

pressure up to 50 bar, biogas, stream 6, follows to two heat exchangers in order to heat recovery

217

and reducing load of the coolers. In the final stage, biogas stream enters a coolers and its

218

temperature decrease to -45 °C. So stream 9 (50 bar, -45 °C) enters the first separator and after

219

separation, stream 10 (50bar, -45°C) with 73.43 mole percent concentration of methane exits from

220

top and is prepared for second separation stage. Stream 11 follows to EXCHANGER 1 for cooling

221

the hot biogas stream. For preparing stream 10 to enter the second separation stage, it is sent to

222

EXCHANGER 3, after this heat exchanger, temperature of stream 13 reaches to -54.75 °C. Its

223

temperature decreases continuously to -63.45 °C by COOLER3. Then stream 14 (50 bar, -63.45

224

°C) enters an expansion valve to drop pressure and temperature to 40 bar and -70°C. After

225

reaching the mentioned pressure and temperature biogas enters second separator and after that

226

stream 16 (40bar, -70°C) with 86.35 mole percent concentration of methane exits from top and

227

as previous stage biogas goes to EXCHANGER4. After this heat exchanger, temperature of

228

stream 18 reaches to -78.88 °C. Its temperature decreases continuously to -80.83 °C by

229

COOLER3. Then stream 19 (40 bar, -80.83 °C) follows to an expansion valve and its pressure

230

and temperature reaches to 10 bar and -120°C (stream 20). In the last stage, stream 20 enters third

231

separation stage. Upgraded biogas exits from top of the separator and reuse in EXCHANGER 4

232

and EXCHANGER 2 for cooling the inlet hot streams. Residual of separator, exits from the

233

bottom and goes to EXCHANGER 3 to decrease temperature of stream 10. 10

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234

Table 6.

235

Table 7.

236

Figure 2.

237 238

2.3. Amine scrubbing method

239

As shown in Figure 3, stream 1 enters a separator for eliminating some physical or insoluble

240

components, after that raw biogas, stream 2, follows to compressors and its pressure s from 2 bar

241

to 8 bar. Then stream 4 (8 bar, 50 °C) enters from below of the absorption column and also amine

242

(stream 13) enters from top of the absorption column. After absorption process in the column,

243

upgraded biogas exits from top of the column and rich amine exits from the bottom. Polluted

244

amine, stream 6, enters a valve and its pressure decreases from 8 bar to 2.5 bar, and for raising

245

the temperature, stream 7 at 2.5 bar and 15.53 °C, enters the preheating heat exchanger. After

246

that, stream 8 (2.5 bar, 82 °C) enters the heater and its temperature increase to 140 °C, then enters

247

a flash drum. Bottom outlet of the flash drum is rich of amine, but it is not suitable for reusing

248

because of high temperature (140 °C) and it must be cooled. So it is cooled to 77 °C and at the

249

second step it follows to a cooler to reducing the temperature up to 15 °C. After these steps amine

250

is recycled to absorption column. Table 8 presents details of the compressors and coolers. Table

251

9 presents specifications of the main process streams.

252

Table 8.

253

Table 9.

254 255 256 257

Figure 3. 2.4. Caustic wash method

258

As shown in Figure 4, inlet biogas enters a three stage compressor while cooling via three air

259

coolers in order to decreasing temperature of the compressed gas. Table 10 presents details of the 11

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260

compressors and coolers. Table 11 presents specifications of the main process streams. After

261

increasing pressure up to 20 bar, biogas, stream 5, enters from bottom of the absorption column.

262

Caustic solution, stream 12, enters from the top. Upgraded biogas, stream 6, is rich of methane

263

and exits from top of the column, Table 12 shows its properties. For NaOH regeneration, stream

264

7 (20bar, 48 °C) enters the preheater and its temperature increases to 100 °C. Then it follows to

265

desorption column and NaOH impurities are removed. In the desorption column a large amount

266

of water is vaporized and exits from top of the column along with H2S and CO2. Therefore, stream

267

11, fresh water, is add to the regenerated NaOH in order to make up the lost water. Relations 5 to

268

8 show the sodium hydroxide reaction with impurities during the process.

269

𝐻2𝑆 + 𝑁𝑎𝑂𝐻→𝑁𝑎𝑆𝐻 + 𝐻2𝑂

(5)

270

𝑁𝑎𝑆𝐻 + 𝑁𝑎𝑂𝐻→𝑁𝑎2𝑆 + 𝐻2𝑂

(6)

271

𝐻2𝑆 + 2𝑁𝑎𝑂𝐻→𝑁𝑎2𝑆 + 2𝐻2𝑂

(7)

272

𝐶𝑂2 + 2𝑁𝑎𝑂𝐻→𝑁𝑎2𝐶𝑂3 + 𝐻2𝑂

(8)

273

Table 10.

274

Table 11.

275

Table 12.

276

Figure 4.

277 278

3. Results and discussion

279

3.1. Results of Water wash method

280

Due to the presence of acid gasses, in order to predict the physical behavior of the process streams,

281

Wilson SRK equation of state was used. It should be noted that operating condition of the process

282

streams are designed the way that methane concentration in final output reaches to its maximum 12

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283

value.

Due

to

results

of

this

simulation,

Figures

5

284

the water on concentrations of CO2, CH4 and H2S. 4000 kgmole/h is considered to be the most

285

optimal, because of no sensitive changing in diagrams after reaching to the mentioned flow rate,

286

and also there is unacceptable concentration of methane before this value. Figure 7 shows effect

287

of temperature on the separation performance. After 10 °C efficiency of separation decreases by

288

temperature. Figure 8 illustrates effect of pressure on concentrations of CH4 and CO2. Sensitivity

289

of the process to pressure is not considerable. After 5 bar, pressure doesn’t affect the separation

290

efficiency.

291 292

Figure 5.

293

Figure 6.

294

Figure 7.

295

Figure 8.

296 297

3.2. Results of cryogenic separation method

298

In this process Sour SRK equation of state was chosen for predicting the physical properties of

299

the fluids. In cryogenic separation, temperature and pressure are important parameters which can

300

affect the process performance significantly. Assigning a suitable pressure and temperature for

301

each separator is a key point in attaining an efficient process. In every stage of separation

302

temperature and pressure are determined the way that separation of methane and carbon dioxide

303

would reach the greatest possible extent. Figure 9 illustrates effect of changing operating

304

temperature of the 1st separator on methane and carbon dioxide molar flow rate. Suitable

305

temperature is -45°C and the diagram shows biogas cooling up to -30 °C is not effective. Figure

306

10 shows effect of changing operating pressure of the 1st separator on CH4 and CO2 molar flow 13

and

6

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307

rates in the separator output. As can be seen suitable operating pressure is 50 bar because of CH4

308

and CO2 curves distance is highest and it shows high efficiency of separation at this point. After

309

determining optimal operating conditions for 1st separator, optimal conditions for 2nd separator

310

was determined. Figure 11 shows effect of operating temperature of the 2nd separator on methane

311

and carbon dioxide molar flow rate. The optimum temperature for this separation is -70 °C. Figure

312

12 shows effect of operating pressure of the 2nd separator on CH4 and CO2 molar flow rate. The

313

optimum pressure for this separator is 40 bar. In the last step, optimal conditions of the 3rd

314

separator is determined. Figure 13 shows effect of operating temperature of 3rd separator on the

315

methane and carbone dioxide molar flow rate. It is obvious that suitable temperature for this

316

section is -120 °C. Figure 14 shows effect of operating pressure of the 3rd separator, separator

317

with the lowest pressure level (10 bar), on CH4 and CO2 molar flow rate. Based on these charts

318

the most suitable pressure and temperature are those when distance between the curves of CH4

319

and CO2 ,the highest value of methane against the lowest vale of CO2, are at the greatest possible

320

extent. In another word, maximizing flow rate of liquid CO2 from bottom of the separator and

321

extracting the remaining CH4 from top of the separator.

322

Figure 9.

323

Figure 10.

324

Figure 11.

325

Figure 12.

326

Figure 13.

327 328 329

Figure 14. 3.3. Results of Amine scrubbing method

330

Due to presence of acid gasses in the process, ACID GAS equation of state was used to predict

331

the physical behavior of the fluids in the process. The aim of this process is to attain a methane14

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332

rich stream. Therefore, pressure and temperature are considered the parameters for determining

333

the separation efficiency the way that the final output streams would achieve high concentrations.

334

Figure 15 shows effect of DEAmine molar flow rate on concentration of H2S in the outlet stream.

335

Also Figure 16 shows effect of molar flow rate of water on concentration of CO2 & CH4 in the

336

final stream. It can be concluded that the right amount of molar flow rate for this process is 15

337

kgmole/h because with increasing the molar flow rate of amine, changing in separation efficiency

338

is not sensitive. Due to Figure 17 mole fraction of CH4 and CO2 in the final stream are not

339

sensitive to pressure. Figure 18 shows effect of operating temperature on mole fraction of CH4

340

and CO2. Figure 19 shows effect of operating temperature on concentration of H2S on

341

composition of the refined biogas. Amount of CO2 is not sensitive to temperature but in the other

342

hand the amount of CH4 decreases with temperature. Concentrations of H2S in final stream

343

increases with temperature so the most suitable temperature is 30 °C.

344 345 346 347

Figure 15.

348

Figure 17.

349

Figure 18.

350

Figure 19.

Figure 16.

351 352

3.4. Results of caustic wash method

353

In order to predict physical properties of the material streams in this process, Casuistic Treating

354

– SRK equation of state was utilized. Figure 20 shows effect of caustic soda flow rate on

355

concentration of methane in the final output biogas. In order to maximize the methane purity

356

caustic soda flow rate needs to be fixed at 15 kgmole/hr. Figure 21 shows effect of tower’s internal

357

pressure on concentration of methane in the refined biogas. As can be seen suitable pressure for 15

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358

separation is 20 atm. Figure 22 illustrates effect of operating temperature on concentration of

359

CH4. As can be seen the temperature should be set at 60 °C to reach the highest purity.

360

Figure 20.

361

Figure 21.

362

Figure 22.

363 364

3.5. Overall evaluation and comparison of the discussed upgrading methods.

365

Table 12 shows composition of the upgraded biogas (mole %) in under consideration processes.

366

The results indicate that the refined biogases resulting from each process are at the same level of

367

quality. Table 13 presents overview of key parameters of biogas upgrading technologies. It is

368

obvious that the required power in the cryogenic separation is more than other upgrading methods.

369

That is because of the required power in the compressors. Most of the required power in water

370

wash is related to the water pumps. Also methane recovery percentage and its purity percentage

371

in caustic wash is much more than other methods which indicates that caustic wash is and efficient

372

biogas refining method. Table 1 and 13 can be compared in order to comparison the results with

373

similar studies. Also Figure 23 illustrates comparison pattern of electricity consumption for

374

different biogas upgrading methods.

375

Table 12.

376

Table 13.

377

Figure 23.

378 379

8. Conclusion

380

In this study five biogas upgrading methods were simulated and analyzed. The results show that

381

caustic wash method is quite efficient; however, recycling the NaOH is particularly energy16

ACCEPTED MANUSCRIPT

382

intensive and expensive. So to make this process more economical, it is suggested that fresh

383

NaOH to be used and the residuals to be discarded as waste. In the amine scrubbing method, using

384

amines for absorbing CO2 is very effective but absorbing H2S in comparison with other processes

385

does not reach an acceptable range. High pressure water scrubbing is found to be a relatively

386

simple process, compared to the other techniques. It can remove both H2S and CO2 using a water

387

stream, and can handle different temperatures and moistures content. However, the amount of

388

water that has to be used for this process is considerable. Cryogenic separation is a technique that

389

might be feasible when a very large quantity of biogas must to be upgraded. Although amine

390

scrubbing consumes less power but its heat demand is too high. In this research focus was on the

391

process design and operation considerations. However, for an overall feasibility study and

392

comparison between the upgrading methods an economic analysis should also be done.

17

ACCEPTED MANUSCRIPT

BP CHP Cp

Nomenclature Boiling point Combine heat and power Specific heat capacity at constant pressure (kJ/kg °C)

PFD Q Rn

CRF

Capital recovery factor,

S

DEA

Diethanolamine

Sn

The present value of resale or salvage value, $

DIPA DP dr h

Diisopropanolamine Dew point

SRK

Soave-Redlich-Kwong

Discount rate (interest rate)

T

Temperature (°C)

specific enthalpy (kJ/kgmole) High heat value (kJ/m3)

V

Molal flow rate of gas, (mol/h)

W

Electricity (kJ)

High pressure water scrubbing Initial investment, $

x

Mole fraction of solute in liquid ,( mol/h)

Y y*

Mole fraction of solute in gas Equilibrium concentration corresponding to liquidphase composition Total height of packed section , (m)

HHV HPWS In Kya

L LCC

m

Overall volumetric masstransfer coefficient based on gas phase,( kg mol/m3.h.atm) Molal flow rate of liquid ,(mol/h) Life cycle cost, $ Mass flow, (kg/s)

ZT

Greek letter 𝛈 Subscripts a

Process flow diagram Heat transfer The present value of repairing and replacement costs, $ Cross-sectional area of tower, (m2)

Efficiency (%) Inlet

MDEA MEA

Methyldiethanolamine Monoethanolamine

alt b

Alternator Outlet

Mn

The present value of nonfuel operating and maintenance cost, $

mec

Mechanical

P

Pressure (kPa , bar)

393 394 395 396 397

18

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398

References:

399 400 401 402 403 404 405 406 407 408 409 410 411 412 413 414 415 416 417 418 419 420 421 422 423 424 425 426 427 428 429 430 431 432 433 434 435 436 437 438 439 440 441 442

[1] Lisoň L, Kmec M, Čonka Z, Kolcunová I. The utilization of biogas in Slovakia. 2014. [2] Meynell P. Methane. Planning a digester. Prison Stable Court. Clarington, Dorset. Sochen Books; 1976. [3] Christy PM, Gopinath L, Divya D. A REVIEW ON DECOMPOSITION AS A TECHNOLOGY FOR SUSTAINABLE ENERGY MANAGEMENT. International Journal of Plant, Animal and Environmental Sciences. 2013;3(4):44-50. [4] Koudache F, Yala AA. A Contribution to the Optimisation of Biogas Digesters with the Design of Experiments Method. J Int Environmental Application & Science. 2008;3(3):195-200. [5] Prasertsan S, Sajjakulnukit B. Biomass and biogas energy in Thailand: potential, opportunity and barriers. Renewable energy. 2006;31(5):599-610. [6] Tippayawong N, Promwungkwa A, Rerkkriangkrai P. Long-term operation of a small biogas/diesel dual-fuel engine for on-farm electricity generation. Biosystems engineering. 2007;98(1):26-32. [7] Esen M, Yuksel T. Experimental evaluation of using various renewable energy sources for heating a greenhouse. Energy and Buildings. 2013;65:340-51. [8] Tippayawong N, Promwungkwa A, Rerkkriangkrai P. Durability of a small agricultural engine on biogas/diesel dual fuel operation. Iranian Journal of Science and Technology. 2010;34(B2):167. [9] Tippayawong N, Thanompongchart P. Biogas quality upgrade by simultaneous removal of CO 2 and H 2 S in a packed column reactor. Energy. 2010;35(12):4531-5. [10] Abatzoglou N, Boivin S. A review of biogas purification processes. Biofuels, Bioproducts and Biorefining. 2009;3(1):42-71. [11] Kadam R, Panwar N. Recent advancement in biogas enrichment and its applications. Renewable and Sustainable Energy Reviews. 2017;73:892-903. [12] Rasi S, Veijanen A, Rintala J. Trace compounds of biogas from different biogas production plants. Energy. 2007;32(8):1375-80. [13] Wellinger A, Murphy JD, Baxter D. The biogas handbook: science, production and applications: Elsevier, 2013. [14] Persson M, Jönsson O, Wellinger A. Biogas upgrading to vehicle fuel standards and grid injection. Conference Biogas upgrading to vehicle fuel standards and grid injection, vol. 37. p. 1-34. [15] Taner T, Sivrioglu M. A techno-economic & cost analysis of a turbine power plant: A case study for sugar plant. Renewable and Sustainable Energy Reviews. 2017;78:722-30. [16] Esen H, Inalli M, Esen M. Technoeconomic appraisal of a ground source heat pump system for a heating season in eastern Turkey. Energy Conversion and Management. 2006;47(9):1281-97. [17] Taner T, Sivrioglu M. Energy–exergy analysis and optimisation of a model sugar factory in Turkey. Energy. 2015;93:641-54. [18] Esen H, Inalli M, Esen M, Pihtili K. Energy and exergy analysis of a ground-coupled heat pump system with two horizontal ground heat exchangers. Building and Environment. 2007;42(10):3606-15. [19] Taner T. Optimisation processes of energy efficiency for a drying plant: A case of study for Turkey. Applied Thermal Engineering. 2015;80:247-60. [20] Rasi S, Läntelä J, Veijanen A, Rintala J. Landfill gas upgrading with countercurrent water wash. Waste Management. 2008;28(9):1528-34. [21] Läntelä J, Rasi S, Lehtinen J, Rintala J. Landfill gas upgrading with pilot-scale water scrubber: performance assessment with absorption water recycling. Applied energy. 2012;92:307-14. [22] Starr K, Gabarrell X, Villalba G, Talens L, Lombardi L. Life cycle assessment of biogas upgrading technologies. Waste Management. 2012;32(5):991-9.

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[23] Johansson N. Production of liquid biogas, LBG, with cryogenic and conventional upgrading technology-Description of systems and evaluations of energy balances. 2008. [24] Petersson A, WeLLInGer A. Biogas upgrading technologies–developments and innovations. IEA Bioenergy. 2009;20. [25] Berstad D, Nekså P, Anantharaman R. Low-temperature CO2 removal from natural gas. Energy Procedia. 2012;26:41-8. [26] Ryckebosch E, Drouillon M, Vervaeren H. Techniques for transformation of biogas to biomethane. Biomass and bioenergy. 2011;35(5):1633-45. [27] Aroonwilas A, Veawab A. Characterization and comparison of the CO2 absorption performance into single and blended alkanolamines in a packed column. Industrial & engineering chemistry research. 2004;43(9):2228-37. [28] Huertas J, Giraldo N, Izquierdo S. Removal of H2S and CO2 from Biogas by Amine Absorption: INTECH Open Access Publisher, 2011. [29] Mehrpooya M, Vatani A, Mousavian S. Optimum design of integrated liquid recovery plants by variable population size genetic algorithm. The Canadian Journal of Chemical Engineering. 2010;88(6):1054-64. [30] Lin SH, Shyu CT. Performance characteristics and modeling of carbon dioxide absorption by amines in a packed column. Waste Management. 1999;19(4):255-62. [31] Kim S, Kim H-T, Chi B. Optimization of CO2 absorption process with MEA solution. Carbon Dioxide Utilization for Global Sustainability. 2004;153:429-34. [32] Palmeri N, Cavallaro S, Bart J. Carbon dioxide absorption by MEA: a preliminary evaluation of a bubbling column reactor. Journal of Thermal Analysis and Calorimetry. 2008;91(1):87-91. [33] Picciotti M. Optimize Caustic Scrubbing Systems. HYDROCARBON PROCESSING. 1978;57(5):201-9. [34] Bahadori A. Chapter 3 - Fresh and spent caustic units and chemical injection systems. Essentials of Oil and Gas Utilities: Gulf Professional Publishing; 2016. p. 59-79. [35] Processors G. Suppliers Association (GPSA). Gas Processors and Suppliers Association Engineering Data Book. 2004. [36] Kutsher G, Smith G, Greene P. NOW—Sour-Gas Scrubbing by the Solvent Process. Oil & Gas J (March). 1967;116. [37] Bekkering J, Broekhuis A, Van Gemert W. Optimisation of a green gas supply chain–A review. Bioresource technology. 2010;101(2):450-6. [38] Andriani D, Wresta A, Atmaja TD, Saepudin A. A review on optimization production and upgrading biogas through CO 2 removal using various techniques. Applied biochemistry and biotechnology. 2014;172(4):1909-28. [39] Muñoz R, Meier L, Diaz I, Jeison D. A review on the state-of-the-art of physical/chemical and biological technologies for biogas upgrading. Reviews in Environmental Science and Bio/Technology. 2015;14(4):727-59. [40] Angelidaki I, Treu L, Tsapekos P, Luo G, Campanaro S, Wenzel H, et al. Biogas upgrading and utilization: Current status and perspectives. Biotechnology advances. 2018. [41] McCabe WL, Smith JC, Harriott P. Unit operations of chemical engineering: McGraw-Hill New York, 1993. [42] Tuzson J. Centrifugal pump design: John Wiley & Sons, 2000. [43] Yeaple F. Fluid power design handbook: CRC Press, 1995. [44] Smith EM. Advances in thermal design of heat exchangers: a numerical approach: direct-sizing, stepwise rating, and transients: Wiley Online Library, 2005.

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493

Tables: Table 1. Comparison of different pilot and commercial biogas upgrading technologies [13, 26, 37-40] Parameter Electricity consumption (kW/h) Pre cleaning Methane loss (%) Methane content in upgraded gas (%) Operation Pressure Pressure at outlet Cold/ hot utility requirement N2 and O2 removal

Water wash 0.25 -0.3

Cryogenic 0.76

Amine wash 0.05 – 0.25

Caustic wash 0.05 – 0.25

No 0.5-2 >96

No 0.1 - 2 >97

No <0.1 >99

No >99

4-10

80

nf

nf

7-10 No

8-10 Yes

4-5 Yes

4-5 Yes

No

Yes

No

No

494 495

Table 2. Main equations of the process equipment.

496 Parameters

Formulas

Parameters

Pumps

Net positive suction head Fluid velocity Pressure at impeller inlet Fluid vapor pressure Specific weight of fluid

Correlation between outlet temperature and pressure 𝑉

2

𝑃

V= 2𝑔(NPSH ‒

𝑃 𝑆𝑊

Compressors

𝑃𝑣

Consumption power Efficiency

+ 𝑆𝑊 [42][37]

2 𝑃𝑣 𝑉 + ) 2𝑔 𝑆𝑊

P=𝑆𝑊(NPSH ‒

[43]

2

Pv= ‒ 𝑆𝑊(NPSH ‒ 𝑆𝑊 =

𝑃 ‒ 𝑃𝑣 𝑁𝑃𝑆𝐻 ‒

Acceleration of gravity

𝑃𝑣

NPSH= 2𝑔 + 𝑆𝑊 ‒ 𝑆𝑊 [43]

𝑔=

𝑉

2 𝑃

𝑃 𝑉 ‒ ) 2𝑔 𝑆𝑊

[43]

[42]

2 𝑉 2𝑔 𝑃

𝑣

[43]

2(NPSH ‒ 𝑆𝑊 + 𝑆𝑊

Entropy generated

𝑆𝑔𝑒𝑛 = 𝑚𝑖𝑛(𝑆𝑜𝑢𝑡 ‒ 𝑆𝑖𝑛) [42]

497 498 499 21

Formulas 𝑇𝑜𝑢𝑡.𝑠 𝑇𝑖𝑛

𝑃𝑜𝑢𝑡

=(𝑃 ) 𝑖𝑛

𝑘 ‒1 𝑎 𝑘 𝑎

[42]

𝑤 = 𝑚𝑖𝑛(ℎ𝑜𝑢𝑡 ‒ ℎ𝑖𝑛) × 𝜂𝑚𝑒𝑐 × 𝜂𝑎𝑙𝑡 [42] 𝜂𝑡ℎ =

𝑊𝑠 𝑊

=

𝑇𝑜𝑢𝑡.𝑠 ‒ 𝑇𝑖𝑛 𝑇𝑜𝑢𝑡 ‒ 𝑇𝑖𝑛

[42]

Heat exchanger Exchange heat LMTD method heat transfer capability Entropy generated

𝑄 = 𝑚(ℎℎ.𝑖𝑛 ‒ ℎℎ.𝑜𝑢𝑡) [44] 𝑇 𝐶𝑃𝑐𝑚𝑐𝑑𝑇𝑐 𝐶𝑝.ℎ𝑚ℎ

𝑇 = 𝑇𝑜𝑢𝑡 + ∫0 𝑐

[44]

𝑆𝑔𝑒𝑛 = 𝑚𝑐(𝑆ℎ.𝑖𝑛 ‒ 𝑆ℎ.𝑜𝑢𝑡) [44]

ACCEPTED MANUSCRIPT

500 501 502

Table 3. Specifications of the biogas feed.

503

Flow rate

20 (kgmole/hr)

Pressure

2 bar

Temperature

25 ℃

Composition CH4 (%)

61.1

CO2 (%)

36.93

O2 (%)

0.98

N2 (%)

0.98

NH3 (ppm)

3

H2S (ppm)

124

504 505 506

Table 4. Specifications of the main process streams. Top outlet from regenerator Flow rate (kgmole/hr)

Bottom absorber column outlet

108.9

4008

1.2

6

Temperature(˚C) Composition (mole %)

1058

10.7

CH4 CO2 O2 N2

0.44 7.71 19.27 72.53

0.01 0.18 0.0001 0.0001

H2S (ppm)

110

110

NH3 (ppm)

0

0

Pressure (bar)

507 508 509 510 22

ACCEPTED MANUSCRIPT

511 512

Table 5. Details of the water scrubbing process equipment.

513

Item COMP 1 COMP 2 Item

514

COOLER 1 COOLER 2

Compressors Outlet Pressure (bar) 4.5 8 Coolers Inlet Temperature Outlet (°C) Temperature (°C) 123.4 40 95.93 10 Inlet Pressure (bar) 2 4.5

Energy Consumption (kW) 16.2 11.7 Energy Consumption (kJ/h) 66440 48400

Table 6. Specifications of the main process streams.

515

Bottom outlet from SEP1 4.98

Top outlet from SEP2 11.61

Bottom outlet from SEP2 3.415

Bottom outlet from SEP3 0.8047

50

50

40

40

2

-45

-45

-70

-70

-120

Top outlet from SEP1 Flow rate (kgmole/hr)

15.02

Pressure (bar) Temperature(℃) Composition (mole %)

73.43

23.91

86.35

29.51

1.48

24.1 1.25 1.25

75.63 0.26 0.19

H2S (ppm)

100

24

10.06 1.5 1.55 0

69.98 0.29 0.2 100

98.48 0.01 0.01 0

NH3 (ppm)

0

3

0

0

0

CH4 CO2 O2 N2

516 517

Table 7. Details of cryogenic separation process equipment. Item COMP 1 COMP 2 COMP 3 Item COOLER 1 COOLER 2 COOLER 3 COOLER 4 COOLER 5

Compressors Outlet Pressure (bar) 8 25 50 Coolers Inlet Temperature Outlet (°C) Temperature (°C) 161.6 60 179 79 24 -45 -54.75 -63.45 -78.88 -80.33 Inlet Pressure (bar) 2 8 25

23

Energy Consumption (kW) 29.62 26.18 15.68 Energy Consumption (kJ/h) 82590 85140 11550 20280 8315

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518 519 520 521

Table 8. Details of amine scrubbing process equipment. Item COMP 1 Item

522

COOLER 1 COOLER 2 HEATER1

Compressors Inlet Pressure Outlet Pressure (bar) (bar) 2 8 Coolers and Heaters Inlet Temperature Outlet (°C) Temperature (°C) 100.5 50 77.3 15 82 140

Energy Consumption (kW) 29.62 Energy Consumption (kJ/h) 40084 1063000 1064000

Table 9. Specifications of the main process streams.

523

Flow rate (kgmole/hr)

Absorption Bottom outlet column 22.09

Amine regenerator top outlet 7.129

8

2.5

39.43

140

Pressure (bar) Temperature(℃) Composition (mole %)

0.02

0.07

32.35 0 0

99.27 0 0

H2S (ppm)

108

100

NH3 (ppm)

1

1

67.58

0.03

CH4 CO2 O2 N2

DEAmine

524 525 526

Table 10. Details of caustic wash process equipment. Item COMP 1 COMP 2 Item COOLER 1 COOLER 2 HEATER 1

Inlet Pressure (bar) 2 8

Compressors Outlet Pressure (bar) 8 20

Coolers and Heaters Inlet Temperature Outlet (°C) Temperature (°C) 161.6 60 159 60 48 100

527 528 529 24

Energy Consumption (kW) 29.62 23.08 Energy Consumption (kW) 82590 83160 511700

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530 531 532

Table 11. Specifications of the main process streams.

533

Flow rate (kgmole/hr)

NaOH regenerator top outlet 8.37

Caustic column bottom outlet 53.68

1.2

20

100

48

Pressure (bar) Temperature(℃) Composition (mole %) CH4 CO2 O2 N2 H2S (ppm)

0.02

0.00015

84.88 0 0 120

33.76 0 0 124

0

1

0 14.97

42.923 23.31

NH3 (ppm) NaOH H2O

534 535 536 537 538

Table 12. Composition of the upgraded biogas (mole %). stream CH4

Raw biogas

60.37

CO2

Water wash

Amine scrubbing

Cryogenic

Caustic wash

95.51

95.68

95.46

96.53

36.49

0.14

1.7

1.16

0

N2

0.97

2.14

1.54

1.7

1.56

O2

0.97

1.8

1.53

1.6

1.56

NH3 (ppm)

2.9

1

<1

0

0

H2S (ppm)

124.32

<1

12.3

0

0

539 540 541 542 543 544 545 546 547 548 549 550 551 25

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552 553 554

Table 13. Overview of the key parameters of biogas upgrading technologies. Water Wash

Cryogenic

Amine Wash

Caustic Wash

Amount of

38.8479

71.4912

29.9369

21.1398

electricity demand (kW) Amount of heat demand

114840

207875

1103048

* 511700

5-15

(-)126 – (-)45

106-160

50-70

4-10

10-50

5-10

15-20

Methane recovery (%)

98

94

99

99.99

off gas treatment (Methane loss> 1%)

Yes

Yes

Yes

No

Water demand

Yes No

No No

Yes Yes

Yes Yes

(kJ/h) Range of

Temperature of process( in columns ) (°C) Range of

operating pressure (bar)

Demand on chemical substance

555 556 557 558 559 560 561 562 563 564 565 566 567 568 569 570 571 572 573 574 575 576 577 578 579 580 581 26

ACCEPTED MANUSCRIPT

582 583 584 585 586 587

Figures:

588 589

Figure 1. Process flow diagram of the water scrubbing method.

590

591 592 593

Figure 2. Process flow diagram of the cryogenic separation method.

594

27

ACCEPTED MANUSCRIPT

595 596 597 598 599 600

601 602 603 604 605 606

Figure 3. Process flow diagram of the amine scrubbing method.

Figure 4. Process flow diagram of the NaOH scrubbing (Caustic wash) method.

28

ACCEPTED MANUSCRIPT

120

ppm

100 80 60 40 20 0 50

1050

2050

3050

4050

5050

6050

7050

8050

kgmole/h

607

Figure 5. Effect of water molar flow rate variation on concentration of H2S.

608 609 610 611 612

Mole percent of CO2 and CH4 (%)

613 100 90 80 70 60 50 40 30 20 10 0 0

1000

2000

3000

4000

5000

6000

7000

8000

kgmole/h

614 615 616

CH4

CO2

Figure 6. Effect of water molar flow rate variation on concentration of CO2 & CH4.

617 618 619 29

ACCEPTED MANUSCRIPT

620 621

Mole fraction

1 0.8 0.6 0.4 0.2 0 10

11

12

13

14

15

16

17

18

Temprature (°C ) CO2

622

624

Figure 7. Effect of operating temperature variation on mole fraction of CH4 & CO2. Mole percent of CO2 and CH4

623

CH4

100 80 60 40 20 0 0

100

200

300

400

500

600

700

800

Pressure (kPa)

625 626

CH4

CO2

Figure 8. Effect of operating pressure variation on mole fraction of CH4 & CO2.

627 628 629 630 631 632

30

ACCEPTED MANUSCRIPT

633

kgmole/ h

15 10 5 0 -60

-55

-50

-45

-40

-35

-30

-25

-20

-15

Temprature (°C ) CH4

634 635 636

CO2

Figure 9. Effect of operating temperature of the 1st separator variation on CH4 & CO2 molar flow rate.

kgmolehr

637 14 12 10 8 6 4 2 0 20

25

30

35

40

45

50

55

60

65

70

Pressure (bar)

638 639 640

CH4

CO2

Figure 10. Effect of operating pressure of the 1st separator variation on CH4 & CO2 molar flow rate.

641

31

ACCEPTED MANUSCRIPT

kgmole/h

12 10 8 6 4 2 0 -80

-75

-70

-65

-60

-55

-50

-45

Temprature (°C ) CH4

642 643 644

CO2

Figure 11. Effect of operating temperature of the 2nd separator variation on CH4 & CO2 molar flow rate.

645

kgmole/hr

12 10 8 6 4 2 0 20

25

30

35

40

45

50

Pressure (bar)

646 647 648

CH4

CO2

Figure 12. Effects of operating pressure of the 2nd separator variation on CH4 & CO2 molar flow rate.

649

32

ACCEPTED MANUSCRIPT

kgmole/hr

12 10 8 6 4 2 0 -130

-120

-110

-100

-90

-80

-70

Temprature (°C) CH4

650 651 652

CO2

Figure 13. Effect of operating temperature of the 3rd separator variation on CH4 & CO2 molar flow rate.

653

kgmiole/hr

12 10 8 6 4 2 0 2

4

6

8

10

12

14

Pressure (bar)

654 655 656 657 658 659 660

CH4

CO2

Figure 14. Effect of operating pressure of the 3rd separator variation on CH4 & CO2 molar flow rate.

33

ACCEPTED MANUSCRIPT

120

ppm

100 80 60 40 20 0 0

5

10

15

20

25

30

35

40

kgmole/h

661 662 663

Figure 15. Effect of molar flow rate of DEAmine variation on concentration of H2S. 100

%

80 60 40 20 0 0

5

10

15

20

25

30

35

40

kgmole/hr CH4

664

666

Figure 16. Effect of molar flow rate of water variation on concentration of CO2 & CH4. Mole percent of CO2 and CH4 (%)

665

CO2

100 80 60 40 20 0 5

6

7

8

9

10

11

Pressure (bar)

667 668

CH4

CO2

Figure 17. Effects of operating pressure variation on mole fraction of CH4 & CO2. 34

ACCEPTED MANUSCRIPT

Mole percent of CO2 and CH4 (%)

669

100 80 60 40 20 0 0

10

20

30

40

50

60

70

80

90

Temprature (°C) CH4

670 671

CO2

Figure 18. Effects of operating temperature variation on mole fraction of CH4 & CO2.

672 673 80 70

ppm

60 50 40 30 20 10 0 0

10

20

30

40

50

60

Temprature (°C)

674 675

Figure 19. Effect of operating temperature variation on concentration of H2S.

676 677

35

70

Mole percent of methane (%)

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96.535 96.53 96.525 96.52 96.515 96.51 12

12.5

13

13.5

14

14.5

15

15.5

16

16.5

17

Molar flow kgmole/h

678 679

Figure 20. Effects of molar flow rate of NaOH variation on concentration of CH4.

Mole percent of methane (%)

680 96.6 96.5 96.4 96.3 96.2 96.1 96 95.9 95.8 95.7 95.6 5

10

15

20

25

Pressure (bar)

681 682

Figure 21. Effect of operating pressure variation on concentration of CH4.

683 684

36

30

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96.7 96.6

CH4 %

96.5 96.4 96.3 96.2 96.1 96 95.9 95.8 55

60

65

70

75

80

Temprature (°C )

685

Figure 22. Effects of operating temperature variation on concentration of CH4.

686

Kw/kgmole

687 688 689 690 691 692

average of similar studies this study Water Wash

Cryogenic

Amine Wash

Caustic Wash

Axis Title

693 694 695 696

this study

average of similar studies

Figure 23. Comparison pattern of electricity for biogas upgrading methods

37

ACCEPTED MANUSCRIPT

   

Biogas upgrading processes are investigated and analyzed. Amine scrubbing process consumes less power but the required hot utility is high. The required power in the cryogenic separation is considerable. Water wash process is a simple and economic method.