Viability GTL NA Gas Market

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Special Report LNG/Gas Processing DevelopmentsE. SalEhi, W. NEl and S. SavE, Hatch Ltd.,

Calgary, Alberta, Canada

Viability of GTL for the North American gas market

New developments in horizontal drilling, in combinationwith hydraulic fracturing, have greatly expanded producersability to recover natural gas and oil from shale plays in North

America. High shale gas activity has increased dry shale gasproduction in the US by around five timesfrom 1 trillion cu-

bic feet (Tcf) in 2006 to 4.8 Tcf in 2010which is over 20% of

the dry natural gas production volume in the US.1,2Considering that there are 750 Tcf of technically recover-

able shale gas resources in the Lower 48 states, the shale gasportion of the US overall dry gas production is forecast to riseto 40%50% over the next two decades.1,2,3 Likewise, in Can-ada, the technically recoverable shale gas total of 355 Tcf pro-

vides a promising resource, as it is more than five times the 62Tcf of proven reserves of conventional natural gas in Canada.4Projections show that total US and Canadian shale gas produc-tion will increase from about 9 billion cubic feet per day (Bcfd)in 2010 to over 25 Bcfd in 2025. 5

Shale gas: A game-changer for North America. Shalegas has caused the Henry Hub spot price to drop from above$12 per thousand standard cubic feet (Mscf) in June 2008 toless than $4/Mscf since January 2012. Gas was traded below$3/Mscf in the first half of 2012. The low gas price is not onlya result of cheap production methods developed during thelast few years, but also of general oversupply in an isolatedNorth American market.6

Associated gas production from liquids-rich shale plays andthe large number of wells drilled in the last several years aremajor contributors to the present supply and demand situationfor gas and, consequently, to the collapse in gas prices.7 Howev-er, as expected, price correction has been occurring since early

autumn 2012 due to production cutbacks, switches from coal-fired to gas-fired power generation, and higher demand duringthe cold season. Most references claim $3/Mscf to $4/Mscf asthe breakeven price for dry shale gas production, which meansthat a profitable price range of $4/Mscf to $6/Mscf is forecastfor natural gas in the foreseeable future.8,9

Gas transport options. The main challenge of monetizinggas resources is logistical. Natural gas reserves close to gas mar-kets are usually transported via pipeline. Where this is not fea-sible, the gas can be transported with alternative methods, suchas compressed natural gas (CNG), liquefied natural gas (LNG)and gas-to-liquids (GTL), which all address this challenge by

densifying gas and reducing transportation costs. The latteroption converts natural gas through Fischer-Tropsch (FT)

synthesis into liquid hydrocarbons, such as diesel and naphtha.Therefore, GTL does not need to compete in the limited gasmarket, unlike CNG and LNG.

A signif icant reduction in gas prices over the last few yearsand an escalation in oil prices have led to a high spread betweenoil and gas prices. This has improved economics for GTL and

made it the most promising alternative for adding value tonatural gas assets in North America. The lower states of theUS and the western provinces of Canada (Alberta and BritishColumbia) have their own drivers to encourage investment inGTL plants.

Gas-to-liquids process. The GTL process (Fig. 1) has threemain steps:

Feedstock preparation and gasification FT synthesis Product upgrading.Fstok ppton n syngs gnton. The

first step, synthesis gas production, is the most expensive ofthe three processes, accounting for up to 50% of the CAPEX.Therefore, there is significant incentive for developing newtechnologies to decrease the capital cost of syngas production.

Syngas [hydrogen + carbon monoxide (H2 + CO)] is pro-duced through three main commercial technologies: Steammethane reforming (SMR) and autothermal reforming(ATR), which are both catalytic processes; and partial oxida-tion (POX), which is a non-catalytic process. SMR does notneed an air separation unit (ASU), and the H 2:CO ratio isabout 3, which represents an advantage for SMR in H2 pro-duction applications.

Sometimes, a combination of two technologies (ATR and

SMR, or POX and SMR) is used, depending on the down-stream FT technology requirement. The main reactions in-volved in these processes are shown in Table 1.10,11,12

Unlike SMR, in POX, natural gas and oxygen from an ASUproduce syngas at an H2:CO ratio of about 1.6:1.9.

13 Shell de-veloped POX technology to produce syngas at its two GTL fa-cilities in Malaysia and Qatar. Some drawbacks of POX are the

LPG

Naphtha

DieselNatural gasfrom pipeline

O2

Steam

FT tail gas

NG preparation andsyngas production

FT synthesis Product upgrading

Fig. 1. The GTL process.

Originally appeared in:January 2013, pgs 41-48.Used with permission.

HYDROCARBON PROCESSING JANUARY 2013


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high outlet temperature from the reactor, which leads to sootformation, and the high cost of the reactor materials.

FT synthesis requires syngas with an H2:CO ratio of about2, a value higher than that obtained using POX and lower thanthat achievable with SMR.14 ATR technology uses both POXand SMR reactions. Natural gas, steam and oxygen are reactedin a sub-stoichiometric flame (with a steam-to-carbon ratioclose to 1 and an oxygen-to-carbon ratio of 0.500.65), andthen converted further along the catalytic bed to produce syn-

gas with an H2:CO ratio of around 2.Fsh-Topsh synthss. FT synthesis is the catalytic

hydrogenation of CO, which is highly exothermici.e., 165 kJper mole of enthalpy change per mole of CO conversion, asshown in Eq. 1.15

CO + 2 H2jCH2 + H2O H = 165 kJ/mol (1)

Eq. 1 shows that not all the energy in the reactants is trans-ferred to the products; a portion is released as heat, and the re-action is exothermic. However, some heat can be recovered toproduce medium-pressure steam, and then to generate power.Table 2 illustrates the main reactions of FT synthesis.11,15

Due to the exothermic nature of FT reactions, heat removalis the main challenge for the FT reactor design. Improper de-sign results in an increased catalyst deactivation rate and de-creased selectivity of the preferred products.

Aside from heat-removal considerations, the reactor designis influenced by the FT products desired. There are two ver-

sions of FT technology that work at different tem-perature ranges, depending on the required products:low-temperature FT (LTFT) and high-temperatureFT (HTFT).

LTFT, with an operating temperature of 200C250C, produces a mixture of gas and liquid hydro-carbons, with a large fraction of heavy paraffinic waxycompounds, that aims to maximize molecules in thediesel range.

HTFT operates at temperatures of 300C350C.This produces lower-molecular-weight paraffins and olefins inthe gaseous phase, which maximizes gasoline production. A lowchain-growth probability (alpha) of around 0.65 is intentionallychosen for HTFT to avoid hydrocarbon deposition on the cata-lysts, whereas this value is 0.9 or higher for LTFT.

Both LTFT and HTFT technologies operate at pressuresof 18 bar45 bar. Since the HTFT product slate is complex,

it requires significant refining to make it suitable for use astransportation fuel. HTFT is also more favorable for chemicalapplications.15

HTFT reactors are either fluidized bed or circulating fluid-ized bed, whereas LTFT reactors are designed as either multi-tubular fixed bed or slurry bed. Since the formation of a liquidphase in the fluidized-bed reactors will disable the fluidization,no liquid phase is present outside of the catalyst particles inHTFT reactors.16

Both slurry-bed and fixed-bed configurations have advan-tages and disadvantages. Slurry reactors are more efficient inheat transfer compared to multi-tubular fixed-bed reactors.Higher heat transfer in slurry beds leads to improved tempera-ture control, which limits methane production and increasesoutput of heavier hydrocarbons.

In contrast, fixed-bed reactors are less efficient in heat re-moval. A significant task for slurry reactors is removing catalystparticles from the FT wax.17 Fine particles can be produced asa result of catalyst attrition in the slurry phase, which is not aconcern for fixed-bed reactors since the catalyst is stationary.

Fixed-bed reactors are easier to scale up, whereas there ismore uncertainty in scaling up slurry-bed reactors. Also, fixed-

bed reactors are more expensive to build than slurry reactors.However, slurry reactors require more catalyst handling andother auxiliary equipment.

To capture the main benefits of slurry reactors (improvedheat removal) and fixed-bed reactors (simpler catalyst-han-dling systems and lower technology risk), extensive work wasconducted by emerging technology licensors to enhance bothheat and mass transfer in fixed-bed reactors by reducing thesize of the tubes. This achievement has led to the developmentof microchannel fixed-bed reactors. The microchannel FTreactors are significantly smaller in diameter and length com-pared to traditional fixed-bed reactors, and they can utilizemore efficient FT catalysts with a higher heat-release rate andhigher productivity.

Upgrading. FT product upgrading applies the same basic

technologies and catalysts as those used in a crude oil refinery.Upgrading unit design depends on the feed to be processed.11

Table 1. Mn syntetc gs ectons

Rctor Proc tchnooy Rcton

SMRSteam methane reorming (SMR) CH4 + H2O } CO + 3H2

Water-gas shit (WGS) CO + H2O } CO2 + H2

POX Partial oxidation CH4 + 1/2O2} CO + 2H2

ATR

Partial oxidation CH4 + 3/2O2} CO + 2H2O

SMR CH4 + H2O } CO + 3H2

WGS CO + H2O } CO2 + H2

Table 2. Mn FT ectons

Fctor Rcton

Paran ormation nCO + (2n+1)H2} CnH2n+2 + nH2O

Olefn ormation nCO + 2nH2} CnH2n + nH2O

Alcohol ormation nCO + 2nH2} CnH2n+1OH + (n1)H2O

WGS reaction CO + H2O } CO2 + H2

Boudouard reaction 2CO} C + CO2

Carbon deposition CO + H2} C + H2O

Heat removal is the main challenge for the

FT reactor design. Improper design results inan increased catalyst deactivation rate and

decreased selectivity of the preferred products.


LNG/Gas Processing Developments


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For HTFT, the FT products contain considerable amountsof olefins that are removed for chemical applications, whereasthe FT products from LTFT lack sufficient olefins content to

justify their extraction.16

The FT products, after stabilization, are hydroisomerized/hydrocracked to produce more distillates at mild conditions.

Very severe hydroprocessing improves the weak cold proper-ties of produced distillates (i.e., decreasing diesel cloudpoint),but at the expense of lowering the diesel output and increasingthe yield of lighter hydrocarbons.

GTL products market. These products are unique; they areclean, sulfur-free, paraffinic hydrocarbons. Although a broadrange of specialty products can be obtained through the GTLprocess, the focus is on three main products: diesel, naphtha andliquefied petroleum gas (LPG).

The diesel markets in North America and worldwide aresteadily growing. Particularly in Europe, rising demand is driv-en by the road freight sector and by passenger vehicles switch-

ing from gasoline to diesel.15 In the US, the Energy InformationAdministration (EIA) projects that diesel consumption willreach 4.5 million barrels per day (MMbpd) by 2035whichmeans an increase of over 40%.18 Likewise, the National En-

ergy Board of Canada forecasts that domestic diesel consump-tion will increase by about 50% by 2035.19

FT diesel can be used directly or blended with crude oil-derived diesel and burned in existing vehicle engines. FT dieselhas zero sulfur, contains low aromatics, and is mostly comprisedof linear products with a cetane number above 70, compared to

a typical cetane number of 40 for crude oil-derived diesel.Due to these properties, FT diesel has the potential to besold as a premium diesel blendstock. In addition, FT diesel can

be blended with lower-cetane, lower-quality diesels to achievecommercial diesel specifications. Aside from the listed advan-tages, the lower emissions levels of hydrocarbons, CO, NOxand particulate matter (PM) make FT diesel a more promisingfuel vs. conventional diesel.20

FT naphtha is not suitable for gasoline production becauseof its low octane number and linear paraffinic nature. However,it can be utilized as a bitumen diluent in specific markets, suchas the oil sands market in Canada. Canadian producers preferto export their heavy oil for processing at US refineries, for

which diluent is required.To meet pipeline specifications, one third of a barrel of dilu-

ent is required for every barrel of bitumen that is to be pumped.The growing oil sands business in Alberta, Canada has resultedin a corresponding growing market for FT naphtha. According tothe Canadian Association of Petroleum Producers (CAPP) fore-cast, total oil sands production will reach 3.7 MMbpd by 2025,representing an increase of more than double the current level.21

The other potential market for FT naphtha is feedstock forsteam crackers to produce petrochemicals. FT naphthas paraf-finic nature makes it is an ideal feedstock for naphtha crackers,and it gives a higher yield of cracker products (ethylene and pro-pylene), compared to crude oil-derived naphtha. Most naphthasteam crackers are located in Japan and South Korea. In North

America, steam crackers mainly use gas feedstocks.There are also various industrial uses for LPG, primarily as

fuel or as petrochemical feedstock. New in-situ oil sands tech-nologies create an alternative use for LPG, potentially aidingin the extraction of bitumen from oil sands.

GTL economics. The oil-to-gas price spread is the main driveraffecting the viability of GTL. In fact, GTL products, such as FTdiesel and naphtha, will compete directly with crude oil-derivedproducts. The Henry Hub natural gas and West Texas Interme-diate (WTI) crude oil price benchmarks are used as the basis

for the current study. Fig. 2 and Fig. 3 show the EIAs 20112035projections for natural gas and crude oil prices, respectively.The average prices for WTI oil and Henry Hub gas in the

forseeable future are $110/bbl and $5.60/MMBtu, respec-tively. This translates into an oil-to-gas price ratio of about 20,compared to a forecast average of less than 10, as estimated inthe previous 21 years (Fig. 4).

However, the EIAs 2012 projections show a $20/bbl high-er average oil price and a $0.30/MMBtu lower average naturalgas price, which leads to a higher spread between crude oiland natural gas prices. A higher spread means increased profit-ability for GTL.

On average, 10 MMBtu of natural gas is required to produce

1 bbl of GTL product, of which about half is consumed to pro-vide the energy needed for GTL processing and for generating

2

3

4

5

6

7

8

2011 2015 2019 2023 2027 2031 2035

$/MMbtu

Year

Fig. 2. Natural gas (Henry Hub) price projection.18

80

90

100

110

120

130

2011 2015 2019 2023 2027 2031 2035

$/bbl

Year

Fig. 3. Crude oil (WTI) price projection.18




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some power for export. The differential is the energy contentof the liquid product. It means that the average feedstock costis about $56/bbl, utilizing an average gas price of $5.60/MM-Btu for the lifetime of the plant.

A significant portion of operating expenditure (OPEX)for a GTL facility (e.g., labor, maintenance and insurance) is

size- and location-specific, whereas chemicals, catalysts andutilities are not. A rough OPEX estimate of $15/bbl to $20/bbl may be used.15, 23 In addition, $3/bbl is assumed for thetransportation cost of the productsan assumption that isalso location-specific.

As with any process in the oil and gas industry, GTL is cap-ital-intensive; therefore, economy of scale is important. OryxGTL, with $1.2 billion (B) to $1.5 B in capital expenditure(CAPEX) and a capacity of 34,000 bpd, has a specific CAPEXin the range of $35,000 to $44,000 per bpd.

Pearl GTL, which is an integrated upstream and downstreamproject with $20 B in CAPEX and capacities of 140,000 bpdof GTL and 120,000 bpd of NGL, translates to a specific CA-

PEX of $77,000 per bpd. The higher CAPEX for Pearl GTLis due to the cost escalation of engineering and materials from20062007, when Pearl GTL started construction. Oryx GTL

benefited from a lump-sum engineering, procurement and con-struction (EPC) contract, which had been sealed prior to 2006,hence avoiding this period of cost escalation.20

Sasol of South Africa, which is the technology provider aswell as a major stakeholder of the Oryx GTL plant in Qatar,

seeks to build GTL facilities in North America. In the US, thecost estimate for Sasols proposed, 96,000-bpd GTL plant inLouisiana is $8 B to $9 B (approximately $88,000 per bpd).24For this analysis, a specific CAPEX of $100,000 per bpd was as-sumed, which is higher than the Pearl GTL CAPEX and Sasolsestimated CAPEX for the US Gulf Coast. The $100,000 per

bpd translates to an estimated cost of $10/bbl of GTL productsfor a GTL plant running for 30 years.The breakdown for GTL product cost in Fig. 5 shows that

gas feedstock cost is the highest contributing factor to the totalcost of 1 bbl of GTL product. However, where the strandedgas alternatives are to leave the gas alone or to flare it, the ne-gotiated gas price has little relationship to the market price.Therefore, stranded-gas GTL economics are primarily driven

by product price and CAPEX.The breakeven point for GTL lies between $50/bbl and

$100/bbl of the crude oil price, depending mainly on the CA-PEX and the natural gas price.25 To evaluate the viability of ageneric GTL plant in North America, GTL product prices were

forecast based on the EIAs 2011 projection of the WTI price,utilizing the historical relationships between diesel, naphthaand LPG prices and the price of WTI.

The analysis of historical prices shows a relationship betweenUS Gulf Coast ultra-low-sulfur diesel price and WTI price, asseen in Fig. 6. Likewise, Fig. 7 demonstrates the historical LPGprice as a function of WTI. The Mont Belvieu, Texas historicalpropane spot price was assumed for the LPG price, and naphtha

was assumed to be sold at the WTI price projected by the EIA.Assuming a GTL plant with the capacity of Oryx GTL, the

product slate would be 24,000 bpd of diesel, 9,000 bpd of naph-tha and 1,000 bpd of LPG (although Oryx GTL announced aneven higher diesel production at the XTL Summit in London inMay 2012). The internal rate of return (IRR), which is graphedagainst CAPEX in Fig. 8, considers the following items:

The assumptions made for gas price projection (Fig. 2) GTL product price projections (Figs. 3, 6 and 7) OPEX Transportation cost A plant availability of 93%.

As shown in Fig. 8, by increasing CAPEX from $80,000 perbpd to $200,000 per bpd, the IRR will decrease from above20% to below 10%. Fig. 9 also shows IRR as a function of the

0

10

20

30

40

50

60

Feedstock CAPEX OPEX Shipping

$/bbl

Fig. 5. GTL product cost breakdowns.

WTI price, $/bbl

USGulfCoastultra-

low-sulfurdieselprice,

$/b

bl

y = 1.2198x + 0.249

0

20

40

60

80

100

120

140

160

180

50 60 70 80 90 100 110 120

Fig. 6. Historical price relationship between diesel and WTI.26

0

5

10

15

20

25

30

35

40

1990 1995 2000 2005 2010 2015 2020 2025 2030

Crude

oilto

naturalgas

pri

ce

ratio

Year

10

Average EIA: 20

Historical ratioEIA forecast

Current ratio

Fig. 4. Crude oil (WTI) to natural gas (Henry Hub) price ratio.22




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average natural gas price and the average WTI price for the ser-vice life of the plant, at various CAPEXs.

As expected, gas and WTI pricings have a significant ef-fect on the total economics of GTL. The economic evaluationshows that, at a gas price of up to $8/MMBtu, assuming a CA-PEX of $80,000 per bpd (Fig. 9), GTL could still be economical

with an average WTI price of above $120/bbl. However, mostscenarios forecast a gas price of $4/MMBtu to $6/MMBtu forthe foreseeable future.

Conversely, at a CAPEX of $200,000 per bpd, GTL wouldbe viable only at higher crude oil and lower gas prices. Associ-ated gas, as the byproduct of US wet shale plays, could be a goodexample for low-value, or sometimes zero-value, feedstock. Inaddition, electricity as the byproduct of a GTL plant could beexported to improve the IRR; however, it is not included in thiseconomic evaluation.

Furthermore, production of higher-value byproducts, suchas lube oils, paraffins and waxes, has not been considered in thisevaluation. Not: this economic evaluation has been conservative

regarding the pricing for feedstock and GTL products. Selectingthe right location with accessibility to less-expensive gas feed-stock significantly improves economics.

Potential locations for GTL installation in North America.Shale gas development has significantly changed natural gaspricing in North America and gas trade between Canada andthe US. Historically, Canada has been a main gas supplier to theUS, which now produces enough gas to be in oversupply.

The two main alternatives for monetizing natural gas in bothCanada and the US are LNG and GTL. Canada has been plan-ning to install LNG plants in British Columbia, on Canadas

West Coast, to supply Asian marketsparticularly Japan. In theUS, most planned installations are located along the Gulf Coastand target European markets.

Although higher thermal efficiency and proven technologymake LNG an attractive alternative, the product is still soldin the limited natural gas market. Furthermore, LNG exportslikely will not aid in reducing oil imports, of which 70% are con-sumed by the transportation sector. GTL, on the other hand,provides clean transportation fuels and also significantly im-proves US energy security.

Western Canada and the US Gulf Coast each have uniqueadvantages and disadvantages for hosting GTL plants. Canadais witnessing higher labor and construction costs (CAPEX and

OPEX) than the US. Conversely, Canadas huge gas resourcesare landlocked, with no readily available market, which willkeep the Canadian gas price below the US gas price.

The benefit of a lower specific CAPEX in the US is mainlydue to accessibility to a lower-cost labor force. The US GulfCoast, in particular, benefits from proximity to a skilled labor

force and access to the coast. The large products market in theUS also supports the implementation of larger-scale GTL plants.Canada, with the advantage of a lower gas price and growing

naphtha and diesel markets in Alberta, could be a good alterna-tive location, especially for small- to medium-sized GTL plants.

Takeaway. New technological achievements in shale gas recov-ery have led to an oversupply of natural gas in an isolated North

American market. This has caused an unprecedented disconnectbetween oil and gas prices. Economic evaluations have shownthat the wide spread between oil and gas prices is making GTL

viable at a broad range of CAPEX values. GTL installations are

0

5

10

15

20

25

80,000 100,000 150,000 200,000

IRR

,%

CAPEX, $/bpd

Fig. 8. Plant IRR vs. CAPEX.

IRR (%): 0%10% 10%20% 20%30%30% 40% 40%50 %

CAPEX: $80,000/bpd CAPEX: $100,000/bpd

80

100

120

140

2 4 6 8

AverageWTIprice,

$/bbl

Average gas price, $/MMBtu

80

100

120

140

2 4 6 8

AverageWTIprice,

$/bbl


CAPEX: $150,000/bpd CAPEX: $200,000/bpd

100

120

140

2 4 6 8

AverageWTIprice,

$/bbl


80

100

120

140

2 4 6 8

AverageWTIprice,

$/bbl


Fig. 9. IRR vs. average natural gas and WTI prices at various CAPEXs.

y = 0.589x + 3.6856

0

10

20

30

40

50

60

70

80

90

0 20 40 60 80 100 120 140 160

MontBelvieu,

Texaspropanespotprice

(freeonboard)

,$/bbl

WTI price, $/bbl

Fig. 7. Historical price relationship between LPG and WTI.26



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economically feasible at low natural gas prices and high forecastoil prices, even at lofty CAPEX values of around $200,000/bpd.

New developments in FT technology will enable economi-cally viable GTL facilities at a smaller scale, compared to ex-isting industrial facilities. However, one must be careful tounderstand the various challenges in implementing new FT

technology related to gas-loop optimization, total process in-tegration to meet a suitable product slate, catalyst handling,efficient startup, commissioning and operations, and a pro-cess design to support a zero-holdup system.

A holistic view is required to consider and integrate thesefactors in a practical manner. An efficient gas-loop design,along with the appropriate level of modularization and an ef-fective project delivery strategy, is known to impact the IRR

by 3%5%. This gives a signif icant boost to overall projectviability. Conversely, negating some of the practical aspectsof commercializing technology might lead to schedule andstartup delays, thereby having the opposite effect on IRR .

LiTeraTure ciTed1 Review of emerging resources: US shale gas and shale oil plays, US Energy

Information Administration, July 2011.2 Butler, N., Shale gas and global energy security,Energy Economist, 2011.3 Fueling North Americas energy future, IHS CERA, 2010.4 Country overview: Canada, US Energy Information Administration, October 16,

2012.5 Canadas shale gas, Canadian Association of Petroleum Producers, February 5, 2010.6 Shale fueling a looming energy credit crunch,Petroleum Economist, May 10, 2012.7 After the gold rush: A perspective on future US natural gas supply and price, The

Oil Drum, February 8, 2012.8 Brown, D., What is the cost of shale gas play?AAPG Explorer,April 2011.9 Shell has learned from its Pearl GTL project and costs can be cut: Voser, Platts,

March 7, 2012.10 Aasberg-Petersen, K., J. H. Bak Hansen, T. S. Christensen and I. Dybkjaer,

Technologies for large-scale gas conversion, Applied Catalysis A: General, Vol.

221, 2001.11 Velasco, J. A., Gas to liquids: A technology for natural gas industrialization inBolivia,Journal of Natural Gas Science and Engineering, Vol. 2, 2010.

12 Liu, J. A., Kinetics, catalysis and mechanism of methane steam reforming, MScthesis, Worcester Polytechnic Institute Chemical Engineering Department, 2006.

13 Vosloo, A. C., Fischer-Tropsch: A futuristic view,Fuel Processing Technology,Vol. 71,2001.

14 Wilhelm, D. J., D. R. Simbeck, A. D. Karp and R. L. Dickenson, Syngas pro-duction for gas-to-liquids applications: Technologies, issues and outlook, Fuel

Processing Technology, Vol. 71, 2001.15 Tijm, P., Gas-to-Liquids, Fischer-Tropsch, Advanced Energy Technology, Futures

Pathway, Bookland Direct, 2010.16 Steynberg, A. P., Introduction to Fischer-Tropsch technology, Studies in Surface

Science and Catalysis, Vol. 152, 2004.17 De Klerk, A., Fischer-Tropsch Refining, Wiley-VCH, 2011.18 Annual projections to 2035, US Energy Information Administration, April 2011.

19 Canadas energy future: Energy supply and demand projections to 2035Energymarket assessment, National Energy Board of Canada, October 17, 2012.

20 Rahmim, I., Special report: GTL, CTL finding roles in global energy, Oil & GasJournal, March 24, 2008.

21 Crude oil, markets and pipelines, Canadian Association of PetroleumProducers, June 2011.

22 Natural gas and crude oil prices in AEO2009, US Energy InformationAdministration.

23 Gas-to-liquids: A reserve ready to be tapped, IHS CERA, July 14, 2011.24 Sasol eyes growth in North America, exit from Iran, Hydrocarbon Processing,September 10, 2012.

25 McCracken, R., Prostrate before Pearl,Energy Economist,July 2011.26 Spot prices for crude oil and petroleum products, US Energy Information

Administration.

EbrahiM SalEhi is a process engineer with more than nine

years o experience with operating and EPC companies,

including our years o PhD research in biouels and two years o

ield experience in a petrochemical complex in southern Iran. His

industry experience has taken place mainly in natural gas,

including conceptual and pre-easibility studies on GTL in

western Canada and study opportunities or developing

compressed natural gas (CNG) and adsorbed natural gas (ANG) in Iran. Mr. Salehis

recent work experience involves the gasiication and Fischer-Tropsch areas o a GTL

pre-easibility study with Hatch, and he has developed an in-depth understandingo gasiication, Fischer-Tropsch, and upgrading technologies. Mr. Salehi received

the Industrial R&D Fellowship (IRDF) award or Hatch rom the Natural Sciences

and Engineering Research Council (NSERC) o Canada.

WESSEl NEl is a senior process engineer at Hatch with more

than 14 years o experience. O these 14 years, 12 were

dedicated to Fischer-Tropsch-related projects, including 10

years at Sasol. Mr. Nel has been the lead Fischer-Tropsch

engineer on a number o Hatchs CTL, GTL and biomass-to-

liquids (BTL) studies in recent years, and the project manager

or recent GTL studies. He has developed an extensive

understanding o established and upcoming GTL technologies rom a broad

range o licensors. Mr. Nels skills include conceptual to detailed process design,

process simulation, lowsheet optimization, economic evaluation, and project

and engineering management.

SaNjiv SavE is the director o oil and gas (hydrocarbon

processing) with Hatchs oil and gas business unit. He has over

20 years o proessional experience with both operating and

consulting companies, in the areas o project and business

management or multidisciplinary engineering, procurement

and construction (EPC) projects in the energy sector. Mr.

Saves speciic areas o technical expertise include heavy oil

upgrading and non-conventional ossil uelsnamely oil sands, oil shale, gas-to-

liquids (GTL), coal-to-liquids (CTL), and carbon capture and sequestration. His

solid technical qualiications, organizational and management skills, and ability

to transcend cultural barriers have led to the successul execution o several

projects. Also, his strong research and development background has contributed

to the publication o several articles, chapters and patents.

Article copyright 2013 by Gulf Publishing Company. All rights reserved. Printed in U.S.A.

Not to be distributed in electronic or printed form, or posted on a website, without express written permission of copyright holder.

Hatch is an employee-owned, multidisciplinary professional EPCM services firm that delivers a comprehensive array oftechnical and strategic services, including consulting, technology, and operations services to the Mining, Metallurgical, Energy,and Infrastructure sectors. Hatch is internationally known for its anything-to-liquids (XTL) and LNG experience and is currentlyinvolved with one of the worlds largest LNG projects, the Gorgon Project. Hatch has served clients for over 80 years and has

project experience in more than 150 countries around the world. With 11,000 people in over 65 offices, the firm currently hasmore than $35 billion projects currently under management.

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