A Potential of CO2 Utilization in Highly Contaminated Natural Gas:

Application of Combined Dry-Steam Reforming for Methanol Production

Directed studies

Rendra Bayu Haristyawan

M.Eng. Student

Steering & Technical Advisory Committee Meeting

Houston, April 16 2015

1

Myself

• Rendra Bayu Haristyawan

• Nationality: Indonesia

• Married, 1 son

• Education: • Bachelor degree in Chemical Engineering, Bandung Institute of Technology

(2008)

• M.Eng Student in Chemical Engineering, Texas A&M (Fall 2013 – now)

• Working experiences: • PT PERTAMINA, Indonesian state owned oil & gas company (2008 – 2013)

• Engineering projects: • Oil and gas field development

• NGL extraction and fractionation

• Mini LNG plant

• Upstream business development

2

Outline

•Introduction • Study Objective

• Literature Review

• Methodology

• Results & Discussion

• Conclusions

3

Introduction

Natural Gas

• Cleaner burning fuel, 60% lower in CO2 emissions compared with other fuels

• Popular due to its versatility, efficiency, and availability

• A 65% demand growth is expected by 2040 (relatives to 2010)

IEA: “Golden Age of Natural Gas”

Ref[1]: 2015 Outlook for Energy, ExxonMobil 4

Introduction

5 Ref[2]: Burgers, W.F.J., et al., Worldwide development potential for sour gas. Energy Procedia, 2011. 4: p. 2178-2184.

Hydrocarbon volumes contain 15-80% CO2

Natural Gas

• Some of natural gas contaminated with sour gas (CO2, H2S) ≈ 141 TCF (4 TNm3) [2]

• High CO2 content (15 to 80%) --> technical and commercial challenges[2,3,4]

• Highly contaminated natural gas resources are primarily located at:

• Southeast Asia/Northwest Australia • Central USA • North Africa • Middle East

Introduction

East Natuna Block[5,6,7]

6

• Discovered in Dec 1973 • Contractors: AGIP (1970 – 1978) Exxon – Pertamina (1978 – 2009)

• Gas composition:

East Natuna Block

• Reserves: 222 TCF(6.3 TNm3) total or 62 TCF(1.75 TNm3 ) Natural Gas

• 45 TCF(1.27 TNm3 ) of hydrocarbon is considered ultimately recoverable

• Located in offshore Natuna Sea • Current contractor: Pertamina (35%), ExxonMobil

(35%), Total (15%) and PTTEP (15%)

Outline

• Introduction

•Study Objective • Literature Review

• Methodology

• Results & Discussion

• Conclusions

7

Study Objective

Directed study objectives:

• Explore and evaluate potential use of CO2 as an alternative on monetizing natural gas from East Natuna Block

8

Thermodynamic Model

Reformer Optimization

Preliminary Process

Simulation

Preliminary Economic Analysis

• Mathematical equilibrium model • Gibbs energy minimization

model

• Thermodynamic preferences • Coke formation region

• Optimum reformer operating condition

• Reforming processes comparison

• Non Linear problem (NLP)

• Heat & material balance • Heat integration &

optimization

• NPV & IRR analysis • Risk Analysis (Monte Carlo)

Issues to be analyzed:

Outline

• Introduction

• Study Objective

•Literature Review • Methodology

• Results & Discussion

• Conclusions

9

CO2 Management

CO2 in non-chemical processes:

• Enhanced Oil (EOR) & Gas Recovery (EGR)[8]

• CO2 gas is injected into the reservoir to expand and push additional oil/gas to a production wellbore

• Increases the recovery 20 to 40 percent of the original oil in place (primary recovery is only about 10%)

• Carbon storage/sequestration[8]

• CO2 gas is injected into the depleted reservoir/safe place underground for storage:

• abandoned or depleted oil and gas fields.

• salt caverns

• abandoned coal seam sites

• deep saline formations

• hydrate region to form CO2 hydrate

• igneous/metamorphic rocks

10

CO2 Management

11 In operation, terminated, initiated[9]

Potential use of CO2

CO2 in chemical processes[10]: Hydrogenation

• CO2 + 3H2 CH3OH + H2O (Methanol)

• 2CO2 + 6H2 C2H5OH + 3H2O (Ethanol)

• CO2 + H2 CH3OCH3 (DME)

Hydrocarbon Synthesis

• CO2 + 4H2 CH4 + 2H2O (or higher HCs)

• 2CO2 + 6H2 C2H4 + 4H2O (Ethylene)

Carboxylic Acid Synthesis

• CO2 + H2 HCOOH (Formic Acid)

• CO2 + CH4 CH3COOH (Acetic Acid)

Graphite Synthesis

• CO2 + H2 C + H2O (Graphite)

12

Amine Synthesis

• CO2 + 3H2 + NH3 CH3NH2 + 2 H2O (Methylamines and higher amines)

• CO2 + 2NH3 NH2CONH2 (Urea)

Hydrolysis and Photo-catalytic Reduction

• CO2 + 2H2O CH3OH + O2 Methanol

• CO2 + H2O HCOOH + ½O2 Formic Acid

• CO2 + 2H2O CH4 + 2O2 Methane

• Biological conversion Micro algae

Other Reactions

• C6H5C2H5 + CO2 C6H5C2H3 + CO + H2O (Styrene)

• CO2 + C3H8 C3H6 + H2 + CO (Propylene)

• CO2 + CH4 2CO + H2 (Dry Reforming-syngas)

Reforming Processes - SynGas Generation

Type of Reforming Process[11,12]:

Process ∆𝐻298𝑜 (kj/mol)

Steam reforming

CH4 + H2O CO + 3H2 206 CnHm + nH2O nCO + (n+m/2) H2 1175 (for nC7H16) CO + H2O CO2 + H2 -41

Catalytic/non catalytic partial oxidation CH4 + ½ O2 CO + H2 -38

Autothermal reforming CH4 + 1½O2 CO + 2H2O -520 CH4 + H2O CO + 3H2 206 CO + H2O CO2 + H2 -41

Dry/CO2 reforming CH4 + CO2 2CO + 2H2 247

Lurgi Shell, Texaco

KBR Air Products ICI

KBR Lurgi Haldor Topsoe

13

SynGas to Methanol

14 Ref[13]: M. Limbach and S.A. Schunk, “Acrylates from alkenes and CO2, the stuff that dreams are made of”, Symposium CO2

als Wertstoff (2012)

Outline

• Introduction

• Study Objective

• Literature Review

•Methodology • Results & Discussion

• Conclusions

15

Thermodynamic Study – Equilibrium Model

• Gibbs minimization: Equilibrium occurs when G at minimum[16,17]

• Method of Lagrange’s undetermined multipliers[16,17] • Find a set of ni which minimize Gt for specified temperature (T), pressure

(P), and feed composition

Where:

∆𝐺𝑓𝑖0 is the standard Gibbs of formation of species i,

ɸ i is the fugacity coefficient of species i,

λk the Lagrange multiplier for element k, yi molar composition

∆𝐺𝑓𝑐0 is standard Gibbs of formation of carbon (solid phase)

𝜆𝑖 is Lagrange multiplier

𝑛𝑖 ∆𝐺𝑓𝑖𝑜 + 𝑅𝑇 ln

𝑦𝑖𝜙 𝑖𝑃

𝑃𝑜+ 𝜆𝑖𝑎𝑖𝑘 + 𝑛𝑐 Δ𝐺𝑓𝐶 𝑆

°

𝑁−1

𝑖=1

= 0

𝐺𝑡 = 𝑛𝑖𝐺𝑖 = 𝑛𝑖

𝑁

𝑖=1

𝜇𝑖 = 𝑛𝑖𝐺𝑖°

𝑁

𝑖=1

+ RT 𝑛𝑖

𝑁

𝑖=1

ln𝑓𝑖

𝑓𝑖°

𝑁

𝑖=1

16

Thermodynamic Study – Equilibrium Model

• Standard Gibbs energy of formation[17]

∆𝐺° = ∆𝐻° − 𝑇∆𝑆°

∆𝐻° = ∆𝐻0° + 𝑅

∆𝐶𝑃°

𝑅𝑑𝑇

𝑇

𝑇0

∆𝑆° = ∆𝑆0° + 𝑅

∆𝐶𝑃°

𝑅

𝑑𝑇

𝑇

𝑇

𝑇0

∆𝐺° = ∆𝐻0° + 𝑅

∆𝐶𝑃°

𝑅𝑑𝑇

𝑇

𝑇0

− 𝑇∆𝑆0° − 𝑅𝑇

∆𝐶𝑃°

𝑅

𝑑𝑇

𝑇

𝑇

𝑇0

∆𝐺° = ∆𝐻0° −

𝑇

𝑇0∆𝐻𝑜

° − ∆𝐺0° + 𝑅

∆𝐶𝑃°

𝑅𝑑𝑇

𝑇

𝑇0

− 𝑅𝑇 ∆𝐶𝑃

°

𝑅

𝑑𝑇

𝑇

𝑇

𝑇0

∆𝑆° = ∆𝐻0

° − ∆𝐺0°

𝑇0

17

Thermodynamic Study – Equilibrium Model

• Fugacity coefficient, ɸ i • For ideal gas ɸ I is unity

• If phase is ideal mixture/solution, ɸ i become ɸ𝑖 (pure component)

• For real gas system, ɸ I is a function of yi thus calculation is more complex. Need a mixing rule approach.

Peng Robinson Eq. of State[18]

𝑃 = 𝑅𝑇

𝑉𝑚 − 𝑏−

𝑎𝛼

𝑉𝑚2 + 2𝑏𝑉𝑚 − 𝑏2

𝑎 =0.457235𝑅2𝑇𝑐

2

𝑃𝑐

𝑏 = 0.077796𝑅𝑇𝑐

𝑃𝑐

𝛼 = 1 + 𝜅 1 − 𝑇𝑟0.5

2

𝜅 = 0.37464 + 1.54226𝜔 − 0.2699𝜔2

𝑇𝑟 = 𝑇

𝑇𝑐

ln𝜙𝑖 =𝑃𝑉𝑚𝑅𝑇

− 1 − ln𝑃 𝑉𝑚 − 𝑏

𝑅𝑇−

𝑎𝛼

2.828𝑏𝑅𝑇ln

𝑉𝑚 + 2.414𝑏

𝑉𝑚 − 0.414𝑏

18

Reforming Optimization

Optimization in reforming process on LINGO and AspenTM

Syn. Gas Generation

Compression

H2/CO = 2

CH4 in ? CO2 in ?

H2O in ? P ? T ?

E1 in ? E2 in ?

Syngas H2/CO=2 P=50 bar

Optimization variables: • T • X = nCO2,in/nCH4,in

• Y = nH2Oin/nCH4,in

Optimization constraints: • 700 <= T <= 1273 K (1000 oC) • P = 25 bar (conventional steam reforming) • nH2/nCO =2 • Y>=X (to prevent coke formation region) • 0 <= X <= 2.5 • 0 <= Y <= 4 19

Objective function

Outline

• Introduction

• Study Objective

• Literature Review

• Methodology

•Results & Discussion • Conclusions

20

Equilibrium study

21

• High conversions are preferred at low pressure and high temperature • Addition of steam would enhance CH4 conversion but significantly lower CO2 conversion • Coke deposition is favored at low CO2/CH4 ratio and low H2O/CH4 ratio • Increase of oxidants (CO2 and H2O) in reactant would lower the coke formation temperature

Coke formation reactions[19]: • Methane decomposition: CH4 C + 2H2 ∆H298K = +75 kJ/mol • Boudouard reactions: 2CO C + CO2 ∆H298K = -171 kJ/mol • Carbon formation occur due to methane decomposition reaction above 557 oC (830 K) • Boudouard reaction is preferred at below 700 oC (973 K)

P=25 bar

Coke formation

How to overcome coke formation?

• Catalyst design • Changes in various factors like the characteristics of the support, type of

metal, concentration of metal, promoter, preparation method can result in synthesis of catalysts with increased dispersion and thus greater resistance to deactivation[19]

• Noble metals i.e. Pt, Rh, Ru are resistant to coke formation, but expensive[20-

23].

• Develop cheaper metal catalysts (i.e. Ni, Co) promoted with noble metals (Rh, Pt, Pd, Ru)[24-26]

• Reactor design • Introduce steam or oxygen into reactor[27-31]

• Design and maintain reactor operating temperature to avoid coke deposition region

• Proper start-up and shut-down approach by keeping high steam to methane ratio

22

Reforming Optimization - Results

• The mathematical model is validated with Aspen HYSYS Simulation

• Optimization is solved using LINGO and ASPEN SQP

23

Gas Separation & Processing

Prod. wells

Pipeline gas

LNG

71% CO2 5% CO2

50 ppm CO2

Acid gas separation processes: • Conventional fractionation – Solvent based • Membrane – Solvent based • Ryan-Holmes fractionation • CFZTM

Acid gas Conventional Approach

Gas Separation & Processing

Prod. wells

71% CO2

35% CO2 Dry-Steam Reforming

1.4 Steam/CH4

P=25 bar T=1273 K

Methanol Synthesis

Acid gas separation processes: • Conventional fractionation • Membrane separation

65% CH4

H2:CO=2:1

Acid gas

Methanol

• Economic Potential = 2.2 • Additional saleable reserve ≈ 8.3 TCF

Proposed Approach

Reforming comparison

24

H2:CO=1:1 H2:CO=2:1 Reforming Processes DR-SMR DR-POX DR-SMR DR-POX-SRM Purpose Mixed alcohols Methanol P bar 25 25 25 25 T K 1273 1273 1273 1273 Inlet Composition CH4 1.000 1.000 1.000 1.000 CO2 1.290 0.731 0.546 0.099 H2O 0.612 - 1.421 0.388 O2 - 0.566 - 0.501 Conversion CH4 % 92.86 96.24 91.95 91.56 CO2 % 71.90 54.15 56.09 -32.14 H2O % 0.15 - 43.17 -14.12 O2 % - 100.00 - 100.00 Economic Potential 2.224 2.330 2.506 2.624 CO2 in Nat. Gas % 56.33 42.23 35.30 9.00 Additional reserve (up to) TCF 25.08 15.33 8.22 -

• Economic potential of mixed alcohols synthesis (H2:CO=1:1) fluctuates to methanol synthesis in Indonesian market.

• CO2 consumption in mixed alcohols synthesis is higher than methanol synthesis. But, it leaves high CO2 concentration in the product stream so that requires higher CO2 removal load downstream of reforming process.

• Surprisingly, tri-reforming has slightly better economic potential compared to dry steam reforming process.

• Low CO2 content required in tri-reforming process which requires high CO2 removal load in upstream processes.

• Thus, there is no reason to utilize CO2 at high concentration in the reforming section unless it gives potential cost saving in upstream processes

Case Study – 2000 MMSCFD gas production

Syn-gas adjustment Process • Syn gas compression • CO2 removal

Methanol Purification • Distillation process

Offshore wells 2000 MMSCFD 71% CO2; 28% CH4; 0.5% N2; 0.5% H2S

Acid gas injection 1124 MMSCFD 99.1% CO2; 0.9% H2S

Gas to Reformers 875.6 MMSCFD 34.9% CO2; 64% CH4; 1.1% N2

Upstream Gas Processing & Conditioning • Offshore installations • Gas Separation &

dehydration • Acid Gas Removal • Acid gas

injection/sequestration

Steam generation 17136 tons/day

Dry-Steam Reforming Process • Gas pretreatment process • Reforming process

Syn-gas 2702 MMSCFD 4.9% CO2; 1.6% CH4; 0.4% N2; 50.9% H2; 25.4% CO; 16.7% H2O

Acid gas injection 112 MMSCFD 99.9% CO2

Steam condensate 9582 tons/day

Treated Syn-gas 2145 MMSCFD 1% CO2; 2.1% CH4; 0.5% N2; 64% H2; 32% CO; 0.4% H2O

Purge gas 130 MMSCFD 10.5% CO2; 29.7% CH4; 14.3% CO; 35.7% H2; 24.9% MeOH; 7.2% N2

Methanol production Process • Methanol reactors • Close loop/recycle system • Purge gas MeOH

26158 ton/day 1.5% CO2; 0.9% CH4; 0.08% CO; 0.14% H2; 96.56% MeOH; 0.09% N2; 0.7% H2O

MeOH Product 25263 ton/day 0.7% CO2; 0.1% CH4; 0.0% CO; 0.0% H2; 99% MeOH; 0.0% N2; 0.15% H2O

Flash gas 13 MMSCFD 35% CO2; 37% CH4; 4.2% CO; 7% H2; 12.6% MeOH;4.3% N2

25

BFW

MP Steam 1187 m3

Heat Integration

Cold Stream T in (K) T out (K) Heat flow (GJ/h) C1 298 499 1980.7

C2 303 503 374.5 C3 496 1273 3316.2 C4 324 493 1285.5

C5 374 385 1339.0

Hot Stream T in (K) T out (K) Heat flow (GJ/h) H1 1273 323 5224.7

H2 416 323 329.3 H3 406 323 400.0 H4 487 323 2235.1

H5 375 334 1291.2

26

• Utilities: • Fired Heat

• MP Steam

• Cooling water

• Pinch methodology with minimum approach: 20 K

• Expanded Transshipment model (Papoulias and Grossmann)[32]

1. Min utility cost (LP Problem)

2. Min no. of exchangers (MILP Problem)

Heat Integration - Results Before Heat Integration

(GJ/h) After Heat Integration

(GJ/h)

Hot utility Fired Heater MP Steam

8295.9 2543.0 1454.6 1088.4

Cold utility 9480.2 3730

Minimum number of exchangers: • Above pinch = 11 • Below pinch = 8

27

Preliminary economic evaluation

Basis:

Operating & maintenance, % of FCI 5%

Company tax 25% Escalation Gas price 2%

MeOH price 2% O&M cost 2%

Utility cost 2% Discount per annum 10%

No. of days per annum, days 330 Project life cycle, years 25 Straight line depreciation, years 20

Location factor[33] 1.11 CAPEX Number of train 2

Capacity per train, MT/day 12631.5 Cost per train, MM $ 2566.6 FCI, MM $ 5133.2

Owner &PM Cost, % of TCI 10% TCI, MM $ 5703.5

Price

Gas price, $/MMBTU 5 MeOH price, $/MT 400

Heating price, $/MMBTU 5 Cooling price, $/MMBTU 1.5

Process water, $/m3 1

Feed Gas, MMSCFD 875

MeOH production, MT/day 25263.00 Production efficiency 98%

Ref: Cost per train = 8*(ton/day of MeOH)0.6

Based on 5000 tpd methanol plant with required capital of $1326MM (2014 cost)[34].

28

Preliminary economic evaluation Results:

1. Impact of heat integration implementation

2. Effect number of trains on economic parameters

No. of Trains Train capacity (MT/day)

Without Heat Integration With Heat Integration

NPV ($ MM) IRR (%) NPV ($ MM) IRR (%)

2 12631.5 2307.8 15.1% 4210.7 18.6%

3 8421 1347.0 12.7% 3249.9 16.0%

4 6315.7 564.3 11.0% 2467.2 14.2%

5 5052.6 -107.9 9.8% 1795.0 12.9%

29

3. Sensitivity analysis to gas and methanol price

Risk analysis - Economic evaluation

Capital cost – log normal distribution

Gas price – triangular distribution

Methanol price – triangular distribution Cooling/process water price factor – linear distribution

Economic Analysis

NPV

IRR

Montecarlo simulation

8.9 -30% +50%

Min 200 ML 363 Max 700

Min 2 ML 5 Max 10

Min -50% Max +50%

30

Risk analysis - Economic evaluation

Net Present Value Minimum, MM $ -14963.84 Maximum, MM $ 20618.11 Expected NPV, MM $ 3994.52 P10, MM $ -2198.41 P50, MM $ 3719.96 P90, MM $ 10819.30 Probability NPV<0 22.05%

Internal Rate of Return Minimum, % -17.57 Maximum, % 68.71 Expected IRR, % 17.50 P10 4.29 P50 17.55 P90 30.15 Probability IRR<10 22.05% 31

Outline

• Introduction

• Study Objective

• Literature Review

• Methodology

• Results & Discussion

•Conclusions

32

Conclusions

• An optimization approach on reforming process has been introduced to utilize CO2 in highly contaminated natural gas.

• Combination of dry-steam reforming with methanol production had been studied and the results show attractive economic performances for a given assumptions.

• Methanol production through combined dry-steam reforming provides alternative on monetization of high contaminated natural gas.

• Further integration to the downstream process i.e. DME process is considered important.

• Eliminates methanol purification

• Provides energy saving

• Mixed alcohols synthesis had been studied has similar advantageous as methanol synthesis.

33

Acknowledgments

• Dr. M. Sam Mannan

• Dr. M. El-Halwagi

• Dr. Ray A. Mentzer

• Dr. Richart Vazquez

• Ms. Valerie Green

• Dr. Mohamed N.

• All members of SC & TAC

• All members of MKOPSC

34

References

1. The Outlook of Energy: A view to 2040. 2015, ExxonMobil. 2. Burgers, W.F.J., et al., Worldwide development potential for sour gas. Energy Procedia, 2011. 4: p. 2178-2184 3. Lallemand, F., et al., Extending the treatment of highly sour gases: cryogenic distillation, in Petroleum Technology

Quarterly. 2014. 4. Maqsood, K., et al., Cryogenic carbon dioxide separation from natural gas: a review based on conventional and novel

emerging technologies. Reviews in Chemical Engineering, 2014. 30 5. Thomas Suhartanto, A.P.E.Y., Ahmad Hanif, Hamid Al-Megren, Malcolm L.H. Green, Potential utilisation of Indonesia's

Natuna natural gas field via methane dry reforming to synthesis gas. Catalysis Letter, 2001. 71(1-2): p. 49-54. 6. Suarsana, I.P., Natuna Gas Processing & Recycling, in Petroleum Engineering. 2001, Texas A&M University: Texas, USA. 7. A. Hanif, T.S., MLH Green, Possible Utilisation of CO2 on Natuna's Gas Field Using Dry Reforming of Methane to Syngas.

Society of Petroleum Engineering, 2002(77926) 8. R. E Hester, R.M.H., Carbon capture : sequestration and storage. 2010, Cambridge, UK: The Royal Society of Chemistry 9. Carbon sequestration, in Science. 25 September 2009. p. 1644-1645 10. T. A. Hertwig, A.X., S. Indala, R.W. Pike, F.C. Knopf, J.R. Hopper, C.L. Yaws, Integrated Chemical Complex and

Cogeneration Analysis System: Energy Conservation and Greenhouse Gas Management Solutions. Proceedings of the Sustainable Engineering Topical Conference, Sustainable Design Methodology, AIChE Annual Meeting, Indianapolis, IN., 2002(19f)

11. Natural Gas: Fuel or Feedstock?, in Sustainable Strategies for the Upgrading of Natural Gas: Fundamentals, Challenges,and Opportunities, V.P. Eric G. Derouane, Francisco Lemos, Fernando Ram a Ribeiro, Editor. 2003, Springer, NATO Public Diplomacy Division: Dordrecht, Netherlands

12. Cheng, W.-H. and H.H. Kung, Methanol Production and Use. 1994, New York: Marcel Dekker 13. M. Limbach and S.A. Schunk, “Acrylates from alkenes and CO2, the stuff that dreams are made of”, Symposium CO2 als

Wertstoff (2012) 14. Nwaoha, C. and D.A. Wood, A review of the utilization and monetization of Nigeria's natural gas resources: Current

realities. Journal of Natural Gas Science and Engineering, 2014. 18: p. 412-432 16. Kim, W.S., et al., The process design and simulation for the methanol production on the FPSO (floating production,

storage and off-loading) system. Chemical Engineering Research and Design, 2014. 92(5): p. 931-940. 17. Van Ness, H. C. and M., Abbot M., 2008, Thermodynamics. Perry's Chemical Engineer's Handbook. s.l. : McGraw Hill,

pp. 4-33. 18. Smith, J. M., Van Ness, H. C. and Abbot, M. M., 2001. Introduction to Chemical Engineering Thermodynamics. s.l. :

McGraw Hill. 35

References

19. Peng, Ding-Yu and Robinson, Donald B. 1976, A New Two-constant Equation of State, Ind. Eng. Chem. Fundam., p. Vol 16 No.1

20. Pakhare, D. and J. Spivey, A review of dry (CO2) reforming of methane over noble metal catalysts. Chem Soc Rev, 2014. 43(22): p. 7813-37

21. Kehres, J., et al., Dynamical Properties of a Ru/MgAl2O4Catalyst during Reduction and Dry Methane Reforming. The Journal of Physical Chemistry C, 2012. 116(40): p. 21407-21415.

22. Pakhare, D., et al., Kinetic and mechanistic study of dry (CO2) reforming of methane over Rh-substituted La2Zr2O7 pyrochlores. Journal of Catalysis, 2014. 316: p. 78-92.

23. Carrara, C., et al., Kinetic and Stability Studies of Ru/La2O3 Used in the Dry Reforming of Methane. Topics in Catalysis, 2008. 51(1-4): p. 98-106.

24. García-Diéguez, M., et al., Nanostructured Pt- and Ni-based catalysts for CO2-reforming of methane. Journal of Catalysis, 2010. 270(1): p. 136-145.

25. Özkara-Aydınoğlu, Ş. and A.E. Aksoylu, CO2 reforming of methane over Pt–Ni/Al2O3 catalysts: Effects of catalyst composition, and water and oxygen addition to the feed. International Journal of Hydrogen Energy, 2011. 36(4): p. 2950-2959.

26. García-Diéguez, M., et al., Characterization of alumina-supported Pt, Ni and PtNi alloy catalysts for the dry reforming of methane. Journal of Catalysis, 2010. 274(1): p. 11-20.

27. Menegazzo, F., et al., Optimization of bimetallic dry reforming catalysts by temperature programmed reaction. Applied Catalysis A: General, 2012. 439-440: p. 80-87

28. Soria, M.A., et al., Thermodynamic and experimental study of combined dry and steam reforming of methane on Ru/ ZrO2-La2O3 catalyst at low temperature. International Journal of Hydrogen Energy, 2011. 36(23): p. 15212-15220

29. Roussière, T.L., Catalytic Reforming of Methane in the Presence of CO2 and H2O at High Pressure, in Fakultät für Chemie und Biowissenschaften. 2013, Karlsruher Institut für Technologie (KIT) - Universitätsbereich genehmigte: Nantes, Franc

30. Amin, N.A.S. and T.C. Yaw, Thermodynamic equilibrium analysis of combined carbon dioxide reforming with partial oxidation of methane to syngas. International Journal of Hydrogen Energy, 2007. 32(12): p. 1789-1798.

31. Zhang, Y., et al., Thermodynamic Analyses of Tri-reforming Reactions To Produce Syngas. Energy & Fuels, 2014. 28(4): p. 2717-2726.

32. Noureldin, M.M.B., N.O. Elbashir, and M.M. El-Halwagi, Optimization and Selection of Reforming Approaches for Syngas Generation from Natural/Shale Gas. Industrial & Engineering Chemistry Research, 2014. 53(5): p. 1841-1855

33. Papoulias, S.A. and I.E. Grossmann, A structural optimization approach in process synthesis-II Heat recovery networks. Computers and Chemical Engineering, 1983. Vol. 7(No. 6): p. 707-721.

34. Cost Indexes, Escalation, and Location Factors, in Project and Cost Engineers' Handbook, Fourth Edition, K.K. Humphreys, Editor. 2004, CRC Press. p. 169-199.

35. Ehlinger, V.M., et al., Process Design and Integration of Shale Gas to Methanol. ACS Sustainable Chemistry & Engineering, 2014. 2(1): p. 30-37.

36

Thank You

Questions & Comments

37