LNG/Gas Processing Developments

Originally appeared in: January 13, pgs 41-48. Used with permission. Special Report LNG/Gas Processing Developments E. 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 combination with hydraulic fracturing, have greatly expanded producers ability to recover natural gas and oil from shale plays in North America. High shale gas activity has increased dry shale gas production in the US by around five times from 1 trillion cubic feet (Tcf) in 6 to 4.8 Tcf in which is over % of the dry natural gas production volume in the US. 1,2 Considering that there are 7 Tcf of technically recoverable shale gas resources in the Lower 48 states, the shale gas portion of the US overall dry gas production is forecast to rise to 4% % over the next two decades. 1,2,3 Likewise, in Canada, the technically recoverable shale gas total of 3 Tcf provides a promising resource, as it is more than five times the 62 Tcf of proven reserves of conventional natural gas in Canada. 4 Projections show that total US and Canadian shale gas production will increase from about 9 billion cubic feet per day (Bcfd) in to over 2 Bcfd in 2. Shale gas: A game-changer for North America. Shale gas has caused the Henry Hub spot price to drop from above $12 per thousand standard cubic feet (Mscf) in June 8 to less than $4/Mscf since January 12. Gas was traded below $3/Mscf in the first half of 12. The low gas price is not only a result of cheap production methods developed during the last few years, but also of general oversupply in an isolated North American market. 6 Associated gas production from liquids-rich shale plays and the large number of wells drilled in the last several years are major contributors to the present supply and demand situation for gas and, consequently, to the collapse in gas prices. 7 However, as expected, price correction has been occurring since early autumn 12 due to production cutbacks, switches from coalfired to gas-fired power generation, and higher demand during the cold season. Most references claim $3/Mscf to $4/Mscf as the breakeven price for dry shale gas production, which means that a profitable price range of $4/Mscf to $6/Mscf is forecast for natural gas in the foreseeable future. 8,9 Gas transport options. The main challenge of monetizing gas resources is logistical. Natural gas reserves close to gas markets are usually transported via pipeline. Where this is not feasible, the gas can be transported with alternative methods, such as 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 latter option 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 gas market, unlike CNG and LNG. A significant reduction in gas prices over the last few years and an escalation in oil prices have led to a high spread between oil and gas prices. This has improved economics for GTL and made it the most promising alternative for adding value to natural gas assets in North America. The lower states of the US and the western provinces of Canada (Alberta and British Columbia) have their own drivers to encourage investment in GTL plants. Gas-to-liquids process. The GTL process (Fig. 1) has three main steps: Feedstock preparation and gasification FT synthesis Product upgrading. Feedstock preparation and syngas generation. The first step, synthesis gas production, is the most expensive of the three processes, accounting for up to % of the CAPEX. Therefore, there is significant incentive for developing new technologies to decrease the capital cost of syngas production. Syngas [hydrogen + carbon monoxide (H 2 + CO)] is produced through three main commercial technologies: Steam methane reforming (SMR) and autothermal reforming (ATR), which are both catalytic processes; and partial oxidation (POX), which is a non-catalytic process. SMR does not need an air separation unit (ASU), and the H 2 :CO ratio is about 3, which represents an advantage for SMR in H 2 production applications. Sometimes, a combination of two technologies (ATR and SMR, or POX and SMR) is used, depending on the downstream FT technology requirement. The main reactions involved in these processes are shown in Table 1.,11,12 Unlike SMR, in POX, natural gas and oxygen from an ASU produce syngas at an H 2 :CO ratio of about 1.6:1.9. 13 Shell developed POX technology to produce syngas at its two GTL facilities in Malaysia and Qatar. Some drawbacks of POX are the Steam O 2 Natural gas from pipeline NG preparation and syngas production Fig. 1. The GTL process. FT tail gas FT synthesis Product upgrading Diesel Naphtha LPG HYDROCARBON PROCESSING JANUARY 13

high outlet temperature from the reactor, which leads to soot formation, and the high cost of the reactor materials. Heat removal is the main challenge for the FT reactor design. Improper design results in an increased catalyst deactivation rate and decreased selectivity of the preferred products. FT synthesis requires syngas with an H 2 :CO ratio of about 2, a value higher than that obtained using POX and lower than that achievable with SMR. 14 ATR technology uses both POX and SMR reactions. Natural gas, steam and oxygen are reacted in a sub-stoichiometric flame (with a steam-to-carbon ratio close to 1 and an oxygen-to-carbon ratio of..6), and then converted further along the catalytic bed to produce syngas with an H 2 :CO ratio of around 2. Fischer-Tropsch synthesis. FT synthesis is the catalytic hydrogenation of CO, which is highly exothermic i.e., 16 kj per mole of enthalpy change per mole of CO conversion, as shown in Eq. 1. 1 CO + 2 H 2 j CH 2 + H 2 O ΔH = 16 kj/mol (1) Eq. 1 shows that not all the energy in the reactants is transferred to the products; a portion is released as heat, and the reaction is exothermic. However, some heat can be recovered to produce medium-pressure steam, and then to generate power. Table 2 illustrates the main reactions of FT synthesis. 11,1 Due to the exothermic nature of FT reactions, heat removal is the main challenge for the FT reactor design. Improper design results in an increased catalyst deactivation rate and decreased selectivity of the preferred products. Table 1. Main synthetic gas reactions Reactor Process technology Reaction SMR Steam methane reforming (SMR) CH 4 + H 2 O } CO + 3H 2 Water-gas shift (WGS) CO + H 2 O } CO 2 + H 2 POX Partial oxidation CH 4 + 1/2O 2 } CO + 2H 2 Partial oxidation CH 4 + 3/2O 2 } CO + 2H 2 O ATR SMR CH 4 + H 2 O } CO + 3H 2 WGS CO + H 2 O } CO 2 + H 2 Table 2. Main FT reactions Factor Paraffin formation Olefin formation Alcohol formation Reaction nco + (2n+1)H 2 } C n H 2n+2 + nh 2 O nco + 2nH 2 } C n H 2n + nh 2 O nco + 2nH 2 } C n H 2n+1 OH + (n 1)H 2 O Aside from heat-removal considerations, the reactor design is influenced by the FT products desired. There are two versions of FT technology that work at different temperature ranges, depending on the required products: low-temperature FT (LTFT) and high-temperature FT (HTFT). LTFT, with an operating temperature of C 2 C, produces a mixture of gas and liquid hydrocarbons, with a large fraction of heavy paraffinic waxy compounds, that aims to maximize molecules in the diesel range. HTFT operates at temperatures of 3 C 3 C. This produces lower-molecular-weight paraffins and olefins in the gaseous phase, which maximizes gasoline production. A low chain-growth probability (alpha) of around.6 is intentionally chosen for HTFT to avoid hydrocarbon deposition on the catalysts, whereas this value is.9 or higher for LTFT. Both LTFT and HTFT technologies operate at pressures of 18 bar 4 bar. Since the HTFT product slate is complex, it requires significant refining to make it suitable for use as transportation fuel. HTFT is also more favorable for chemical applications. 1 HTFT reactors are either fluidized bed or circulating fluidized bed, whereas LTFT reactors are designed as either multitubular fixed bed or slurry bed. Since the formation of a liquid phase in the fluidized-bed reactors will disable the fluidization, no liquid phase is present outside of the catalyst particles in HTFT reactors. 16 Both slurry-bed and fixed-bed configurations have advantages and disadvantages. Slurry reactors are more efficient in heat transfer compared to multi-tubular fixed-bed reactors. Higher heat transfer in slurry beds leads to improved temperature control, which limits methane production and increases output of heavier hydrocarbons. In contrast, fixed-bed reactors are less efficient in heat removal. A significant task for slurry reactors is removing catalyst particles from the FT wax. 17 Fine particles can be produced as a result of catalyst attrition in the slurry phase, which is not a concern for fixed-bed reactors since the catalyst is stationary. Fixed-bed reactors are easier to scale up, whereas there is more uncertainty in scaling up slurry-bed reactors. Also, fixedbed reactors are more expensive to build than slurry reactors. However, slurry reactors require more catalyst handling and other auxiliary equipment. To capture the main benefits of slurry reactors (improved heat removal) and fixed-bed reactors (simpler catalyst-handling systems and lower technology risk), extensive work was conducted by emerging technology licensors to enhance both heat and mass transfer in fixed-bed reactors by reducing the size of the tubes. This achievement has led to the development of microchannel fixed-bed reactors. The microchannel FT reactors are significantly smaller in diameter and length compared to traditional fixed-bed reactors, and they can utilize more efficient FT catalysts with a higher heat-release rate and higher productivity. WGS reaction CO + H 2 O } CO 2 + H 2 Boudouard reaction 2CO } C + CO 2 Carbon deposition CO + H 2 } C + H 2 O 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 HYDROCARBON PROCESSING JANUARY 13

For HTFT, the FT products contain considerable amounts of olefins that are removed for chemical applications, whereas the 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 properties of produced distillates (i.e., decreasing diesel cloudpoint), but at the expense of lowering the diesel output and increasing the yield of lighter hydrocarbons. $/MMbtu 8 7 6 4 3 2 11 1 19 23 27 31 3 Year Fig. 2. Natural gas (Henry Hub) price projection. 18 $/bbl 13 1 9 11 1 19 23 27 31 3 Year Fig. 3. Crude oil (WTI) price projection. 18 GTL products market. These products are unique; they are clean, sulfur-free, paraffinic hydrocarbons. Although a broad range of specialty products can be obtained through the GTL process, the focus is on three main products: diesel, naphtha and liquefied petroleum gas (LPG). The diesel markets in North America and worldwide are steadily growing. Particularly in Europe, rising demand is driven by the road freight sector and by passenger vehicles switching from gasoline to diesel. 1 In the US, the Energy Information Administration (EIA) projects that diesel consumption will reach 4. million barrels per day (MMbpd) by 3 which means an increase of over 4%. 18 Likewise, the National Energy Board of Canada forecasts that domestic diesel consumption will increase by about % by 3. 19 FT diesel can be used directly or blended with crude oilderived diesel and burned in existing vehicle engines. FT diesel has zero sulfur, contains low aromatics, and is mostly comprised of linear products with a cetane number above 7, compared to a typical cetane number of 4 for crude oil-derived diesel. Due to these properties, FT diesel has the potential to be sold as a premium diesel blendstock. In addition, FT diesel can be blended with lower-cetane, lower-quality diesels to achieve commercial diesel specifications. Aside from the listed advantages, the lower emissions levels of hydrocarbons, CO, NO x and particulate matter (PM) make FT diesel a more promising fuel vs. conventional diesel. FT naphtha is not suitable for gasoline production because of its low octane number and linear paraffinic nature. However, it can be utilized as a bitumen diluent in specific markets, such as the oil sands market in Canada. Canadian producers prefer to export their heavy oil for processing at US refineries, for which diluent is required. To meet pipeline specifications, one third of a barrel of diluent is required for every barrel of bitumen that is to be pumped. The growing oil sands business in Alberta, Canada has resulted in a corresponding growing market for FT naphtha. According to the Canadian Association of Petroleum Producers (CAPP) forecast, total oil sands production will reach 3.7 MMbpd by 2, representing an increase of more than double the current level. 21 The other potential market for FT naphtha is feedstock for steam crackers to produce petrochemicals. FT naphtha s paraffinic nature makes it is an ideal feedstock for naphtha crackers, and it gives a higher yield of cracker products (ethylene and propylene), compared to crude oil-derived naphtha. Most naphtha steam 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 technologies create an alternative use for LPG, potentially aiding in the extraction of bitumen from oil sands. GTL economics. The oil-to-gas price spread is the main driver affecting the viability of GTL. In fact, GTL products, such as FT diesel and naphtha, will compete directly with crude oil-derived products. The Henry Hub natural gas and West Texas Intermediate (WTI) crude oil price benchmarks are used as the basis for the current study. Fig. 2 and Fig. 3 show the EIA s 11 3 projections for natural gas and crude oil prices, respectively. The average prices for WTI oil and Henry Hub gas in the forseeable future are $1/bbl and $.6/MMBtu, respectively. This translates into an oil-to-gas price ratio of about, compared to a forecast average of less than, as estimated in the previous 21 years (Fig. 4). However, the EIA s 12 projections show a $/bbl higher average oil price and a $.3/MMBtu lower average natural gas price, which leads to a higher spread between crude oil and natural gas prices. A higher spread means increased profitability for GTL. On average, MMBtu of natural gas is required to produce 1 bbl of GTL product, of which about half is consumed to provide the energy needed for GTL processing and for generating HYDROCARBON PROCESSING JANUARY 13

some power for export. The differential is the energy content of the liquid product. It means that the average feedstock cost is about $6/bbl, utilizing an average gas price of $.6/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 and utilities are not. A rough OPEX estimate of $1/bbl to $/ bbl may be used. 1, 23 In addition, $3/bbl is assumed for the transportation cost of the products an assumption that is also location-specific. As with any process in the oil and gas industry, GTL is capital-intensive; therefore, economy of scale is important. Oryx GTL, with $1.2 billion (B) to $1. B in capital expenditure (CAPEX) and a capacity of 34, bpd, has a specific CAPEX in the range of $3, to $44, per bpd. Pearl GTL, which is an integrated upstream and downstream project with $ B in CAPEX and capacities of 14, bpd of GTL and, bpd of NGL, translates to a specific CA- PEX of $77, per bpd. The higher CAPEX for Pearl GTL is due to the cost escalation of engineering and materials from 6 7, when Pearl GTL started construction. Oryx GTL benefited from a lump-sum engineering, procurement and construction (EPC) contract, which had been sealed prior to 6, hence avoiding this period of cost escalation. Sasol of South Africa, which is the technology provider as well as a major stakeholder of the Oryx GTL plant in Qatar, Crude oil to natural gas price ratio $/bbl 4 3 3 2 1 6 4 3 Historical ratio 199 199 1 2 3 Year Feedstock CAPEX OPEX Shipping Fig.. GTL product cost breakdowns. Current ratio EIA forecast Average EIA: Fig. 4. Crude oil (WTI) to natural gas (Henry Hub) price ratio. 22 seeks to build GTL facilities in North America. In the US, the cost estimate for Sasol s proposed, 96,-bpd GTL plant in Louisiana is $8 B to $9 B (approximately $88, per bpd). 24 For this analysis, a specific CAPEX of $, per bpd was assumed, which is higher than the Pearl GTL CAPEX and Sasol s estimated CAPEX for the US Gulf Coast. The $, per bpd translates to an estimated cost of $/bbl of GTL products for a GTL plant running for 3 years. The breakdown for GTL product cost in Fig. shows that gas feedstock cost is the highest contributing factor to the total cost of 1 bbl of GTL product. However, where the stranded gas alternatives are to leave the gas alone or to flare it, the negotiated 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 $/bbl and $/bbl of the crude oil price, depending mainly on the CA- PEX and the natural gas price. 2 To evaluate the viability of a generic GTL plant in North America, GTL product prices were forecast based on the EIA s 11 projection of the WTI price, utilizing the historical relationships between diesel, naphtha and LPG prices and the price of WTI. The analysis of historical prices shows a relationship between US Gulf Coast ultra-low-sulfur diesel price and WTI price, as seen in Fig. 6. Likewise, Fig. 7 demonstrates the historical LPG price as a function of WTI. The Mont Belvieu, Texas historical propane 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, bpd of diesel, 9, bpd of naphtha and 1, bpd of LPG (although Oryx GTL announced an even higher diesel production at the XTL Summit in London in May 12). The internal rate of return (IRR), which is graphed against 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 $, per bpd to $, per bpd, the IRR will decrease from above % to below %. Fig. 9 also shows IRR as a function of the US Gulf Coast ultra-low-sulfur diesel price, $/bbl 1 16 14 6 4 y = 1.2198x +.249 6 7 9 1 WTI price, $/bbl Fig. 6. Historical price relationship between diesel and WTI. 26 HYDROCARBON PROCESSING JANUARY 13

average natural gas price and the average WTI price for the service life of the plant, at various CAPEXs. As expected, gas and WTI pricings have a significant effect on the total economics of GTL. The economic evaluation shows that, at a gas price of up to $8/MMBtu, assuming a CA- PEX of $, per bpd (Fig. 9), GTL could still be economical with an average WTI price of above $/bbl. However, most scenarios forecast a gas price of $4/MMBtu to $6/MMBtu for the foreseeable future. Conversely, at a CAPEX of $, per bpd, GTL would be viable only at higher crude oil and lower gas prices. Associated gas, as the byproduct of US wet shale plays, could be a good example for low-value, or sometimes zero-value, feedstock. In addition, electricity as the byproduct of a GTL plant could be exported to improve the IRR; however, it is not included in this economic evaluation. Furthermore, production of higher-value byproducts, such as lube oils, paraffins and waxes, has not been considered in this evaluation. Note: this economic evaluation has been conservative regarding the pricing for feedstock and GTL products. Selecting the right location with accessibility to less-expensive gas feedstock significantly improves economics. Potential locations for GTL installation in North America. Shale gas development has significantly changed natural gas pricing in North America and gas trade between Canada and the US. Historically, Canada has been a main gas supplier to the US, which now produces enough gas to be in oversupply. The two main alternatives for monetizing natural gas in both Canada and the US are LNG and GTL. Canada has been planning to install LNG plants in British Columbia, on Canada s West Coast, to supply Asian markets particularly Japan. In the US, most planned installations are located along the Gulf Coast and target European markets. Although higher thermal efficiency and proven technology make LNG an attractive alternative, the product is still sold in the limited natural gas market. Furthermore, LNG exports likely will not aid in reducing oil imports, of which 7% are consumed by the transportation sector. GTL, on the other hand, provides clean transportation fuels and also significantly improves US energy security. Western Canada and the US Gulf Coast each have unique advantages and disadvantages for hosting GTL plants. Canada is witnessing higher labor and construction costs (CAPEX and Mont Belvieu, Texas propane spot price (free on board), $/bbl 9 y =.89x + 3.686 7 6 4 3 4 6 14 16 WTI price, $/bbl Fig. 7. Historical price relationship between LPG and WTI. 26 OPEX) than the US. Conversely, Canada s huge gas resources are landlocked, with no readily available market, which will keep the Canadian gas price below the US gas price. The benefit of a lower specific CAPEX in the US is mainly due to accessibility to a lower-cost labor force. The US Gulf Coast, in particular, benefits from proximity to a skilled labor force and access to the coast. The large products market in the US 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 alternative location, especially for small- to medium-sized GTL plants. Takeaway. New technological achievements in shale gas recovery have led to an oversupply of natural gas in an isolated North American market. This has caused an unprecedented disconnect between oil and gas prices. Economic evaluations have shown that the wide spread between oil and gas prices is making GTL viable at a broad range of CAPEX values. GTL installations are IRR, % 2 1,, 1,, CAPEX, $/bpd Fig. 8. Plant IRR vs. CAPEX. 14 2 4 6 8 CAPEX: $,/bpd 14 2 4 6 8 CAPEX: $,/bpd 14 2 4 6 8 2 4 6 8 CAPEX: $1,/bpd CAPEX: $,/bpd IRR (%): % % % % % 3% 3% 4% 4% % Fig. 9. IRR vs. average natural gas and WTI prices at various CAPEXs. 14 HYDROCARBON PROCESSING JANUARY 13

economically feasible at low natural gas prices and high forecast oil prices, even at lofty CAPEX values of around $,/bpd. New developments in FT technology will enable economically viable GTL facilities at a smaller scale, compared to existing industrial facilities. However, one must be careful to understand the various challenges in implementing new FT technology related to gas-loop optimization, total process integration to meet a suitable product slate, catalyst handling, efficient startup, commissioning and operations, and a process design to support a zero-holdup system. A holistic view is required to consider and integrate these factors in a practical manner. An efficient gas-loop design, along with the appropriate level of modularization and an effective project delivery strategy, is known to impact the IRR by 3% %. This gives a significant boost to overall project viability. Conversely, negating some of the practical aspects of commercializing technology might lead to schedule and startup delays, thereby having the opposite effect on IRR. Literature cited 1 Review of emerging resources: US shale gas and shale oil plays, US Energy Information Administration, July 11. 2 Butler, N., Shale gas and global energy security, Energy Economist, 11. 3 Fueling North America s energy future, IHS CERA,. 4 Country overview: Canada, US Energy Information Administration, October 16, 12. Canada s shale gas, Canadian Association of Petroleum Producers, February,. 6 Shale fueling a looming energy credit crunch, Petroleum Economist, May, 12. 7 After the gold rush: A perspective on future US natural gas supply and price, The Oil Drum, February 8, 12. 8 Brown, D., What is the cost of shale gas play? AAPG Explorer, April 11. 9 Shell has learned from its Pearl GTL project and costs can be cut: Voser, Platts, March 7, 12. 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, 1. 11 Velasco, J. A., Gas to liquids: A technology for natural gas industrialization in Bolivia, Journal of Natural Gas Science and Engineering, Vol. 2,. 12 Liu, J. A., Kinetics, catalysis and mechanism of methane steam reforming, MSc thesis, Worcester Polytechnic Institute Chemical Engineering Department, 6. 13 Vosloo, A. C., Fischer-Tropsch: A futuristic view, Fuel Processing Technology, Vol. 71, 1. 14 Wilhelm, D. J., D. R. Simbeck, A. D. Karp and R. L. Dickenson, Syngas production for gas-to-liquids applications: Technologies, issues and outlook, Fuel Processing Technology, Vol. 71, 1. 1 Tijm, P., Gas-to-Liquids, Fischer-Tropsch, Advanced Energy Technology, Future s Pathway, Bookland Direct,. 16 Steynberg, A. P., Introduction to Fischer-Tropsch technology, Studies in Surface Science and Catalysis, Vol. 12, 4. 17 De Klerk, A., Fischer-Tropsch Refining, Wiley-VCH, 11. 18 Annual projections to 3, US Energy Information Administration, April 11. 19 Canada s energy future: Energy supply and demand projections to 3 Energy market assessment, National Energy Board of Canada, October 17, 12. Rahmim, I., Special report: GTL, CTL finding roles in global energy, Oil & Gas Journal, March 24, 8. 21 Crude oil, markets and pipelines, Canadian Association of Petroleum Producers, June 11. 22 Natural gas and crude oil prices in AEO9, US Energy Information Administration. 23 Gas-to-liquids: A reserve ready to be tapped, IHS CERA, July 14, 11. 24 Sasol eyes growth in North America, exit from Iran, Hydrocarbon Processing, September, 12. 2 McCracken, R., Prostrate before Pearl, Energy Economist, July 11. 26 Spot prices for crude oil and petroleum products, US Energy Information Administration. Ebrahim Salehi is a process engineer with more than nine years of experience with operating and EPC companies, including four years of PhD research in biofuels and two years of field experience in a petrochemical complex in southern Iran. His industry experience has taken place mainly in natural gas, including conceptual and pre-feasibility studies on GTL in western Canada and study opportunities for developing compressed natural gas (CNG) and adsorbed natural gas (ANG) in Iran. Mr. Salehi s recent work experience involves the gasification and Fischer-Tropsch areas of a GTL pre-feasibility study with Hatch, and he has developed an in-depth understanding of gasification, Fischer-Tropsch, and upgrading technologies. Mr. Salehi received the Industrial R&D Fellowship (IRDF) award for Hatch from the Natural Sciences and Engineering Research Council (NSERC) of Canada. Wessel Nel is a senior process engineer at Hatch with more than 14 years of experience. Of these 14 years, 12 were dedicated to Fischer-Tropsch-related projects, including years at Sasol. Mr. Nel has been the lead Fischer-Tropsch engineer on a number of Hatch s CTL, GTL and biomass-toliquids (BTL) studies in recent years, and the project manager for recent GTL studies. He has developed an extensive understanding of established and upcoming GTL technologies from a broad range of licensors. Mr. Nel s skills include conceptual to detailed process design, process simulation, flowsheet optimization, economic evaluation, and project and engineering management. Sanjiv Save is the director of oil and gas (hydrocarbon processing) with Hatch s oil and gas business unit. He has over years of professional experience with both operating and consulting companies, in the areas of project and business management for multidisciplinary engineering, procurement and construction (EPC) projects in the energy sector. Mr. Save s specific areas of technical expertise include heavy oil upgrading and non-conventional fossil fuels namely oil sands, oil shale, gas-toliquids (GTL), coal-to-liquids (CTL), and carbon capture and sequestration. His solid technical qualifications, organizational and management skills, and ability to transcend cultural barriers have led to the successful execution of several projects. Also, his strong research and development background has contributed to the publication of several articles, chapters and patents. Article copyright 13 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. Ebrahim Salehi esalehi@hatch.ca Wessel Nel wnel@hatch.ca Sanjiv Save ssave@hatch.ca Hatch is an employee-owned, multidisciplinary professional EPCM services firm that delivers a comprehensive array of technical 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 currently involved with one of the world s largest LNG projects, the Gorgon Project. Hatch has served clients for over years and has project experience in more than 1 countries around the world. With 11, people in over 6 offices, the firm currently has more than $3 billion projects currently under management.