SPE-128342-MS

SPE 128342

Economic Viability of Gas-to-Liquids in Nigeria

O. M. Balogun SPE, Laser Engineering and Resources Consultants Ltd. and M.O. Onyekonwu, PTDF Gas Chair, University of Port Harcourt.

Copyright 2009, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the 33rd Annual SPE International Technical Conference and Exhibition in Abuja, Nigeria, August 3-5, 2009. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgement of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract With recent oil price escalation, declining oil reserves and global warming, interest has been shown world-wide in the production of clean liquid fuels through Fischer-Tropsch (FT) Synthesis. FT Synthesis is a proven technology but development of commercial GTL has been very slow. For resource holders, the major challenge is economics thus, the economic viability of GTL calls for critical analysis.

This paper reviewed FT process and investigated its economics with principal interest in the production of Syncrude, DME and Methanol in Nigeria. A sound appraisal technique was later used to measure and rank GTL proposals with the LNG in Nigeria.

The results show that GTL–Diesel would be economically feasible when applied to a typical offshore Niger Delta resource at oil prices of above US$35/bbl and feedstock gas price in range of US$0.25-1.5/mmBtu. GTL-DME economics looks encouraging and could be introduced at a price lower than that of LPG. However GTL-Methanol will only be viable at a distress gas price of US$0.25-0.5/mmBtu and in a condition of preferential tax treatment. LNG and GTL-Syncude have the same value at discount rate of 16.84% with LNG giving higher profits if the cost of capital is less than 16.84%. The profitability of LNG and GTL (Syncrude and DME) is very close, with GTL having a potential superior return at high oil prices and preferable under conditions of limited capital. In Nigeria, GTL-Syncrude could be used to monetize “leftover” gas that doesn’t merit a standalone new

LNG train and provide the country an opportunity to enjoy direct exposure to oil price upsides

Introduction The world’s proved natural gas reserves currently exceeding 5,000 Tcf, have grown at a faster rate than proved oil reserves. Consequently this era has been called the “gas age". However, over 75% of the world’s proved natural gas reserves are not currently accessible by pipeline and majority of those reserves exist in remote location where laying pipelines cannot be economically justified. While LNG on the other hand can be used on much smaller gas fields, the high capital costs involve and long term agreement required to make it profitable has been a major concern. These are some of the reasons for the relatively slow uptake of gas. However, because of the commercial value of natural gas, ways are being sought to bring stranded gas to market.

Natural Gas Hydrate (NGH) and Compressed natural gas (CNG) technologies provide attractive options to solve the stranded gas problem in the oil industry. Technically these technologies are easy to deploy with less requirements for facilities and infrastructure. However, they are beyond the scope of this paper.

Another alternative currently receiving world’s attention is Gas – to – Liquids Technology. The chemical conversion of natural gas into hydrocarbon liquids has been a technological goal for many years. This process was developed by two Germans: Franz Fischer and Hans Tropsch in 1923. Germany successfully used gas derived from coal to feed Fischer-Tropsch plant to produce gasoil for its armies during World War II.

GTL products include liquid fuels such as methanol, Di-Methyl Ether (DME), gasoil, normal paraffin, naphtha and other petroleum refinery type distillate fuels. DME can be used as a substitute for LPG and introduction of certain volume of DME is expected to play its role as a deterrent force to ever – increasing LPG contract price. Though methanol has uncompetitive prices and some legislative constraints, the development of fuel cells for

2 O.M. Balogun SPE 128342

distributed-type power generators or fuel cells for automotive use holds the key to successful introduction of methanol. F-T diesel is highly valuable as a blending stock for petroleum-based diesel fuel, because it has a high cetane number and low aromatic content. It is spotlighted as a clean fuel for next-generation diesel engine.

Even though FT Synthesis has long been a technically proven technology; the development of commercial GTL technology has been piecemeal and slow. The major factors affecting its viability are:

i. Premium gas resource ii. Oil and Gas price (and exposure to oil

upside) and Capital Cost iii. Financial Strength and Freedom to operate iv. Large project execution skills v. Global marketing capability

However the Technology is currently gaining a renewed interest worldwide. This renewed interest has been driven by:

i. Declining oil reserves as against increasing demand for energy around the world

ii. Expanding utilization of natural gas. iii. The recent escalation in oil price and

refining margin iv. Strengthened restriction measures taken

on gas flaring in each of the oil producing country

v. Strengthened measures to counter the issue of automotive emissions to prevent environmental pollution in most countries of world

vi. Avenue for portfolio diversification among the Major Resource Holders

vii. The GTL Technology advances that are reducing the cost of converting larger reserves of natural gas, not readily accessible by pipeline, into high quality liquid fuel products

A large number of industrial and government sponsored programmes to develop commercially viable process options are in various stages of development.

The Nigerian Government recently announced a gas reserves base of about 170 tcf, 120 tcf of which is proven and uncommitted. In addition as much as 90 % of discovered oil reservoirs are estimated to constitute the oil leg to a gas cap. While this situation seems to lend itself well to an LNG exploitation strategy, the logistics of gathering discovered gas to a central point are almost

impossible as these reserves are scattered in small 1-3 tcf deposits among hundreds of fields across Niger Delta. Therefore, with the exception of a few large concentrations, such as the case for Shell’s Bonny LNG plant, much of the country’s gas remains stranded, reinjected or part of the estimated 2 bcf that is flared daily making Nigeria the highest gas flaring country in the world. Thus, effective utilization of natural gas resources being flared daily is an urgent task to be addressed also from the environmental protection standpoint.

Nigeria’s push to end flaring before the end of 2010 means that the Major Resource Holders and Oilfield developers are forced to find outlet for their produced gas. GTL therefore, could be a viable alternative route to commercialize this produced gas. Though LNG and GTL compete for the cheap gas resource and thus far, LNG has been the choice of countries looking to monetize their stranded gas, GTL offers producers an alternative way to commercialize stranded gas and enjoy direct exposure to oil price upsides.

However, for resource holders, the major challenge is economics thus, the economic viability of GTL calls for critical analysis.

This paper reviewed FT process and investigated its economics with principal interest in the production of Syncrude, DME and Methanol in Nigeria. A sound appraisal technique was later used to measure and rank GTL proposals with the LNG in Nigeria.

Gas-to-Liquids Technology Converting Gas-to-Liquid using the Fischer-Tropsch method is a multistep and energy-consuming process. It takes apart molecules of natural gas, predominantly methane, and reassembles them into long-chain molecules. The first step requires input oxygen [O2] separated from air. The oxygen is blown into reactor to strip hydrogen atoms from the methane [CH4]. The products are synthetic hydrogen gas [H2] and carbon monoxide [CO], sometimes called syngas or synthetic gas. The second step uses a catalyst to recombine the hydrogen and carbon monoxide into liquids hydrocarbons. In the last stage, the liquid hydrocarbons are converted and fractionated into products that can be used immediately or blended with others. The Fischer-Tropsch product spectrum consists of a complex multicomponent mixture of linear and branched hydrocarbons and oxygenated products. The Main products are linear paraffin and α-olefins. The overall reactions of the Fischer-Tropsch Synthesis are summarized in Table 1. The

3 Economic Viability of Gas-to-Liquids in Nigeria SPE 128342

hydrocarbon synthesis is catalyzed by metal such as iron, cobalt nickel, and ruthenium. Both iron and cobalt are used commercially these days at a temperature of 200 to 300 oC and pressure of 10 -60 bars. The most well-known product is extremely pure diesel, sometimes known as gasoil. Diesel from the Fischer-Tropsch process, unlike diesel derived from distillation of crude oil, has near-zero sulfur-and nitrogen-oxides content, contains virtually no aromatics, burn with little or no particulate emissions, has high cetane value. Kerosene, ethanol, and Di-Methyl Ether (DME) can also be produced. Another product of the reaction is naphtha that is high in paraffin content. Waxes derived from Fischer-Tropsch process can be pure enough to use for food packaging and cosmetics. Basically GTL Technology involves four (4) process routes:

• Air Separation/Gas Pretreatment. • Syngas Production (Gasification). • Fischer-Tropsch Reaction Synthesis. • Product Upgrading and Separation.

Air Separation and Natural Gas Pretreatment Like LNG projects, it is critically important to have clean gas feedstock comprised only of methane for GTL plants. Trace impurities, especially acid gas and mercury, are detrimental to the process operation. Typical unit operations required to produce such a feed summarized as follows:

• The raw gas is passed to a slug catcher, where condensate is removed

• An acid gas plant removes carbon, hydrogen sulfide and other sulphur compounds. The off gas is passed to Claus plant to recover the sulphur

• Mercury removal is essential to protect the down stream facility

• The gases are dried to remove moisture and other trace impurities

• Turbo expansion cools the gas, and then condensate, LPG and ethane are progressively removed

Oxygen required for the synthesis gas production is produced through cryogenic air separation process. This process has successfully been applied to support gasification worldwide. It is selected based on optimization of the capital cost and power consumption required. The process begins with filtration and compression of air to about 6 bars. The compressed air is then cooled to close-to-

ambient temperature in water/air-cooled heat exchangers. It may be cooled further in a mechanical refrigeration system. This improves the efficiency of impurity removal and minimizes power consumption. Condensed water is removed from the air after each stage of compression and cooling. Water vapor and carbon dioxide are removed in “reversing exchangers" or "molecular sieve units". Further cooling is done in brazed aluminum heat exchangers to bring the air feed to cryogenic temperature (about -300oF or 185oC) against waste gas stream. The exiting waste gas streams are warmed to close-to-ambient air temperature. Recovering refrigeration from the gaseous product streams and waste stream minimizes the amount of refrigeration that must be produced by the plant, however additional cooling is needed. The very cold temperatures needed for cryogenic distillation are created by a refrigeration process that includes expansion of one or more elevated pressure process streams. The next process step is the use of distillation columns to separate the air into desired products. Since oxygen is the desired product, the distillation system will have both “high” and “low” pressure columns. Nitrogen leaves the top of each distillation column; oxygen leaves from the bottom. Argon has a boiling point similar to that of oxygen and will preferentially stay with the oxygen product. If high purity oxygen is required, argon must be removed from the distillation system at an intermediate point. Impure oxygen produced in the initial (higher pressure) column is further purified in the second, lower pressure column. Synthesis Gas Production From the thermodynamic standpoint, it is very difficult if not impossible in many cases, to directly convert methane into a more useful product because of its inertness and stability. Therefore, methane is first converted into a more reactive intermediate product called syngas or synthesis gas (basically H2 and CO gas). The conversion is controlled to produce an appropriate intermediate product ratio based on the desired end products. Unlike methane, synthesis gas is very reactive and can be converted by a wide range of processes into a variety of useful chemicals and materials. The production of synthesis gas is central to downstream Fischer Tropsch process in production of clean liquid fuels. In principal, synthesis gas can be produced from any carbon source e.g. fossil fuels, biocrops or other recyclable material (garbage. Most of the


capital investment for a GTL plant is associated with the syngas-generation step. Six principal technologies for syngas production from natural gas have been commercialized or are at an advanced stage of development. Depending on the source of the feedstock and the method chosen, the raw synthesis gas is produced over a range of concentrations of carbon monoxide, carbon dioxide, and hydrogen. The ratio of hydrogen to carbon monoxide is known as the stoichiometric ratio (RS) of the gas. This ratio is often used to characterize the synthesis gas produced. The six principal technologies for syngas production from natural gas and their applicability are summarized in Table 2. Fischer-Tropsch Synthesis The Fischer-Tropsch synthesis section consists of:

i. FT Reactor. ii. Recycle and Compression of unconverted

synthesis gas. iii. Removal of hydrogen and carbon

monoxide. iv. Reforming of methane produced and

separation of the FT products. Table 1: Major Overall Reactions in the Fischer-Tropsch Synthesis

Synthesis Gas Production 1. Steam Reforming 2. CO2 Reforming 3. Partial Oxidation 4. Water gas shift reaction

224 H3COOHCH +⇔+

224 H2CO2COCH +→+

2221

4 H2COOCH +→+

222 HCOOHCO +⇔+

Fischer-Tropsch Synthesis Main Reactions

5. Paraffins 6. Olefins

Side Reactions

7. Alcohols 8. Boudouard Reaction

Catalyst Modifications

9. Catalyst Oxidation/Reduction

10. Bulk carbide Formation

( ) OnHHCnCOH1n2 21n2n2 +→++ +

OnHHCnCOnH2 2n2n2 +→+

( ) OH1nOHCnCOnH2 22n2n2 −+→+ +

2COCCO2 +→

xMOyHyHOM 22yx +⇔+

xMyCOyCOOM yx +⇔+

yx CMxMyC ⇔+

The most important aspects for the development of commercial Fischer-Tropsch reactors are the high reaction heats and the large number of products with varying vapour pressure (gas, liquid, and solid hydrocarbons). Basically there are two major commercial Fischer-Tropsch processes. They are:

I. Low Temperature Fischer Tropsch process (LTFT).

II. High Temperature Fischer Tropsch Process (HTFT).

Depending on the final products required, either LTFT is used to produce a syncrude with a large fraction heavy, waxy hydrocarbons or HTFT is used to produce light syncrude and olefins. In both cases, some oxygenates are produced as well. The two major FT processes, their applicability and applicable FT reactors are summarized in Table 3. The Alpha Value The FT process produces a hydrocarbon product distribution that can be described by simple polymerization theory. The molar ratio of a product of a given carbon number (CN) to a product of one less carbon number is a constant less than unity. This constant is generally referred to as the alpha value.

α=−=

=1nCNwithproductofMoles

nCNwithproductofMoles

This can be modified to predict the mass fraction (Wn) of product with carbon number n, as:

]/)1log[(log)/log( 2 ααα −+= nnWn The alpha value is an important indicator of the nature of the products that are formed in the synthesis. The value of alpha depends on all of the independent variables in the synthesis. These include the temperature, pressure, stoichiometric ratio of the synthesis gas, the catalyst type, and the age of the catalyst. The alpha value is a good predictor of the components produced in the range of C5 to about C30. This is the range of interest for the production of transport fuels. The amount of methane is more than that predicted depending on the extent of methanation. Ethane is particularly low, and propane and butane are reduced from the ideal. The amount of heavy materials can be reduced by cracking reactions. The ideal variation of product composition is illustrated in Figure 1.


Figure 1: Variation of product composition with Alpha value [1] Although some systems can operate at lower or higher alpha values, the typical FT processes of interest operate in an alpha range of 0.7 to 0.9. As the value of alpha rises, there is a fall in the production of gaseous products (methane to butane) and a concomitant rise in the production of wax (C25+). Over much of range of alpha, the liquid products (the sum of naphtha and distillate) remain essentially constant at about 55% to 60% of the total products. The principal problem for the production of naphtha and diesel is to maximize this liquid yield by secondary processing of the gas and wax fractions. This greatly complicates the overall process flowsheet. The value of alpha can be altered by using catalysts of different formulations, and to some extent by changing process parameters particularly temperature. This is because increasing the temperature lowers the value of alpha. However, in practice a specific technology usually operates over a restricted alpha range. The product from the FT reaction can best be regarded as a synthetic crude oil. There is a very high (in some cases almost 100%) concentration of linear paraffins. Such paraffins make good kerosene and distillate blend stock, but the naphtha fraction is very poor in octane number. Before use as gasoline, the naphtha must be extensively refined. Also produced are heavy waxes that can be hydrocracked to lighter transport fuel fractions. Product Upgrading and Separation Conventional refinery processes can be used for upgrading of Fischer-Tropsch liquid and wax products. A number of possible processes for FT products are: wax hydrocracking, distillate hydrotreating, catalytic reforming, naphtha hydrotreating, alkylation and isomerization. Fuels produced with the FT synthesis are of a high quality

due to a very low aromaticity and zero sulphur content. The product stream consists of various fuel types: LPG, gasoline, diesel fuel, jet fuel. The diesel fraction has a high cetane number resulting in superior combustion properties and reduced emission. The wax fraction in the crude product may be converted to additional diesel with mild hydrocracking by use of conventional technologies, such as those offered for license by Chevron or UOP. The syngas-generation unit must, therefore, produce some excess hydrogen beyond FTS stoichiometric requirements.


Table 2: Principal Technologies for Syngas Production From Natural Gas

Technology Operating Conditions

Catalyst H2/CO SR

Reaction Type Reactor Type Applicability Status

Steam/Methane Reforming (SMR)

19 – 21 bars 800 – 900 oC

Nickel Based 3:1 Endothermic Multitubular/ Fixed Bed

Methanol Production

Commercialized

Autothermal Reforming (ATR)

21 – 22 bars 950 – 1050 oC

Nickel Based 2:1 Endothermic/Exothermic

Adiabatic Fixed Bed

DME/ Synfuel

Commercialized

Non Catalytic Partial Oxidation (POx)

(Gasification)

25 – 100 bars 1050 – 1300 oC

NIL 2:1 Exothermic Refractory lined Pressure Vessel

Synfuel Commercialized

Catalytic Partial Oxidation (CPOx)

ca 1000 oC Rhodium-based monolithic

2:1 Exothermic Refractory lined Pressure Vessel

Synfuel Pilot

Heat Exchange Reforming (HER)

Combined both SMR &ATR Methanol Demonstration Run

Compact Reforming Mechanical approach to conventional SMR Synfuel Demonstration Run

Table 3: Major Fischer Tropsch Processes

FT Process

Reactor Catalyst Catalyst Size Operating Conditions

Capacity (bbl/day)

*Examples

Multitubular Fixed

Bed

1 mm

3000-10000

SAP & SMDS

LTFT

Process

Slurry Phase

Iron or Cobalt

based 20 – 100 microns

180 – 250 oC 10

– 45 bars

3000-17000

SSPDS

Circular Fluidized Bed

About 340 oC

About 6500

SCFB

HTFT

Process

Sasol Advanced Synthol

Iron based only

Fused Catalyst

25 bars

About 2000

* SAP: Sasol Arge Process SMDS: Shell Middle Distillate Synthesis SSPDS: Sasol Slurry Phase Distillate Synthesis SCFB: Sasol Synthol-Circular Fluidized Bed


Typical hydrocracking reactor conditions entail temperatures of 608 to 752oF and pressures of 1,000 to 1,500 psig. The naphtha fraction may be further upgraded to gasoline with catalytic reforming.

Alternatively, the naphtha could be used as steam cracker feedstock for olefins production. The definitions and conventions for the composition and names of the different fuel types are obtained from crude oil refinery process are given in Table 4.

Table 4: Conventions of Fuel Names and Composition Name Synonyms Components Fuel Gas C1 – C2 LPG C3 – C4 Gasoline C5 – C12 Naphtha C8 – C12 Kerosene Jet Fuel C11 – C13 Diesel Fuel oil C13 – C17 Middle Distillate Light Gas Oil C10 – C10 Soft wax C19 – C23 Medium wax C24 – C35 Hard wax C35+

Properties and Uses of FT Synthetic Fuel FT synthetic fuel has the following properties:

• Sulphur free. • Rich in paraffin. • Extremely low aromatics. • Excellent solubility and fungibility with

petroleum product.

The naphtha fraction has an octane number as low as RON40 or below and cannot be used readily as gasoline (petroleum-based naphtha has an octane number of around 50), while it is considered to be suitable as a petrochemical feedstock naphtha for cell-powered automobiles, as it has low sulphur and low aromatics contents. The kerosene fraction has excellent properties such as low sulphur content and its smoke point is around 45 mm (compared with around 20 mm for petroleum based kerosene). There is a good possibility that FT kerosene will be used as a fuel for fuel cells for household use in the future. Moreover, a mixture of FT kerosene and petroleum based jet fuel on 50/50 basis is being supplied as an aviation fuel at the Johannesburg Airport in South Africa. The diesel fuel fraction is highly valuable as a blending stock for petroleum-based diesel, because it has a high cetane number and low aromatics content. FT diesel produced by Mossgas and Shell is exported to the U.S. and European countries either for a diesel fuel or for a blending stock to reduce aromatics and sulphur contents of petroleum-based products.

Furthermore, FT diesel is spotlighted as a clean fuel for next generation diesel engines. Engine test results have confirmed that FT diesel is effective in improving the engine output and reducing emissions in the exhaust gas. Meanwhile, FT diesel has some problems such as poor lubricity and low degree of swelling for seals due to its low sulphur and aromatics contents. However, these problems are considered to be solved by using additives and by changing the design of seals. The demand for methanol is currently established as the feedstock for manufacturing chemicals such as formaldehyde, acetic acid, MTBE, etc. The world’s demand for methanol totaled 25.84 million tons in 1998, including Japan’s demand totaling 1.90 million tons which were totally imported [7]. Methanol as a fuel has a high octane number of RON 109, but its fuel efficiency in terms of fuel economy rate per km-run has a tendency of becoming low due to its low heating value (Net heating values of 3800 kcal/liter compared with 7900 kcal/liter for gasoline). Moreover, methanol is not a suitable fuel for diesel powered automobiles due to its low cetane number of around 3. Close attention is now being focused on methanol as a fuel for fuel cell – powered automobiles. As methanol can be reformed at a lower temperature than gasoline, the use of methanol for this purpose is technically closer to its commercialization. DaimlerChrysler has completed an automobile using methanol as a fuel, which is reaching the


point of its commercialization in the nearest future. Road tests are been conducted in some countries [7]. DME is now being produced by methanol dehydration, and is being used as aerosol propellant as a substitute for CFC (chlorofluoro carbon) gas. The world’s total production of DME stood at 150, 000 tons in 1999, of which Japan produced around 10,000 tons. DME used in Japan is produced domestically, with virtually none imported [7]. DME has low toxicity and has essentially no effect on living body. It is in a gaseous phase under the normal temperature and normal atmospheric pressure, but is easily liquefied when the pressure is raised to about 6 atmospheric. Being similar to propane in properties (with DME having a boiling point of -25.1oC vis-à-vis -42 oC for propane), studies are being made of possibility to introducing DME as a substitute for LPG. Because of its low octane number, DME is not suitable for LPG-powered automobiles, but it can be used as a promising substitute for diesel fuel, because it has a high cetane number of 55-60 and little PM (Particulate Matter) is discharged when used for diesel engines. It has many technical problems, however, such as poor lubricity, making it necessary to use additives for its solution and hence it will take some times to place it into commercial use as a substitute for diesel fuel.

GTL Projects Worldwide Table 5 summarizes the current situation with respect to existing and proposed future GTL plants. The current operating plants with product streams greater than 1000 bpd are located in South Africa,

Malaysia and currently Qatar. Sasol and Mossgas operate the two facilities in South Africa, while the facilities in Malaysia and Qatar are operated by Shell and Sasol respectively. There are many companies addressing the gas to liquids technology, including but not limited to BP/Amoco/Arco, Conoco, ExxonMobil, Mossgas, Rentech, Sasol/Chevron, Shell and syntroleum. This list includes the major oil companies and some niche players who are developing their own approaches to this opportunity. Much of the GTL work to date has been in developing the technology through research utilizing small – scale plants, anything from one barrel per day to two hundred barrels per ay. The Mossgas plant in South Africa is commercially producing liquid fuels from natural gas via three, nine thousand barrel per day trains, while the Sasol plant, also in South Africa, developed the FT synthesis application with gas from coal. The Shell plant at Bintu, Malaysia produces specialty chemicals and waxes, but could be modified to produce middle distillates. Sasol recently commissioned a GTL plant with 34,000 bpd (in two trains) capacity. The various players in this developing industry have many projects at different stages of commitment around the world. Each player is attempting to differentiate their technology on the basis of yield, capital cost size and product. The focus of their strategies includes monetizing stranded gas and the development of niche commodity markets for high value products. In some cases these strategies are supported by companies entering alliances with partners having complementary skills.

Table 5: Summary of Current and Proposed Commercial GTL Plants

Year Operator Location Size (bpd) Products 1955 Sasol South Africa 124,000 Light Olefins & gasoline 1991 Mossgas South Africa 22,000 Gasoline & Diesel 1993 Shell Malaysia 12,500 Waxes, Chemicals, Diesel 2006 Sasol Qatar 34,000 Liquid Fuels Proposed

Rentech USA 1,200 High grade waxes & liquid fuel Syntroleum Australia 10,000 High margin products

Shell Indonesia 70,000 Liquid Fuels ExxonMobil Qatar 100,000 Liquid Fuels

Sasol/Chevron Nigeria 34,000 Liquid Fuels EB, BP, ANGTL Alaska 100,000 Liquid Fuels

Sicor Ethiopia 20,000 Liquid Fuels Sasol/Chevron Australia 30,000 Liquid Fuels

PDVSA Venezuela 15,000 Liquid Fuels


GTL Economics Analysis and Project Evaluation An investment in a manufacturing process can only earn more than the cost capital if the plant design can present a process that is capable of operating under conditions, which yield profit. In the final analysis, the answer to the question “will we realize a profit from this venture?” almost always determines the true value of any project. In order to ascertain the profit making power of any project for its owner, the cost of the project is estimated and the realizable revenue from product(s) sales are determined, and the values then weighed against the investment cost. The final difference is a measure of the profitability of any project. Methodology The hypothetical GTL Technology shall be for chemical conversion of natural gas into readily transportable liquid fuels – FT synthetic fuel, Methanol and DME. Assuming that the plants are built in Nigeria using the natural gas produced in the Niger Delta region as a feedstock, and that these GTL products are exported to Europe, USA or consuming locally. The various project assumptions and estimates for hypothetical GTL (Diesel, DME and Methanol) are presented in the proceeding sections. Three steps which include estimation of Cash flows, required rate of return and an application of investment decision rules shall be employed in the evaluation of each investment proposal. These investment decision rules may be referred to as capital budgeting techniques, or investment criteria. A sound appraisal technique shall be used to measure the economic worth of each investment project – GTL Diesel, DME and Methanol. The essential property of a sound technique is that it should maximize the investor’s wealth. The following characteristics should also be possessed by a sound investment evaluation criterion:

i) It should consider all cash flows to determine the true profitability of the projects.

ii) It should provide for an objective and unambiguous way of separating good projects from bad projects.

iii) It should help in ranking projects according to their profitability

iv) It should recognize that bigger cash flows are preferable to smaller ones and early cash flows are preferable to later ones

v) It should help to choose among mutually exclusive projects that which maximizes the shareholder’s wealth

vi) It should be a criterion which is applicable to any conceivable investment project independent of other

GTL - FT Syncrude The proposed Sasol/Chevron GTL project in Escravos, Nigeria (EGTL 1) with production capacity of 34,000bbl/day shall be the basis for all economic estimates. The summary of the preconditions of economic evaluations used in this work is presented in Table 6. In recent years, developments have enabled the unit capital cost of the GTL projects to be significantly reduced. The identified costs associated with the proposed plants have been collated from recent industry publications and various GTL vendors. From this research the capital investment estimated for GTL – syncrude is 1,028.42 MMUS$ (a unit cost of 30,248 US$/BBL) as shown in Table 6 This compares favourably with the published total investment of 997 MMUS$ (29,000US$/BBL) for Sasol Oryx 1 in Qatar [4]. However, considering inflation, other logistics and the so called “Nigerian factor” the estimated CAPEX is escalated by 30% to give a total capital investment of 1,336.94 MMUS$ (39,322 US$/BBL). It is important to appreciate that for so many years, there was no new GTL plant constructed until June 2006 when Sasol Oryx 1 in Qatar was commissioned. Until a number of new GTL plants have been constructed, uncertainty in the level of capital cost will remain. The ratio of capital investment for the first, second and third year of 25%, 35% and 40% respectively shall be applied and the plant construction period shall be 3 years. The load factor for first, second and third year of 90%, 95% and 100% would be applied. The same $6.0/bbl non-feedstock operating cost of Sasol’s Oryx 1 is assumed. This includes cost of raw material basically catalyst, utility cost (only for process since for electricity and cooling water in GTL plant are self supported), owner costs, chemical cost, maintenance cost, operating labour, laboratory cost, supervision, plant overhead, capital charges, product transportation cost, insurance, local taxes and royalties. However the most significant component of a plant’s overall operating cost appears to be the cost of the natural gas feedstock to the facility. In this study, the profitability index and other economic indices are estimated


based on different gas prices ranging from 0.5 – 1.5US$/MMBtu. Double declining balance depreciation method, been the most widely used in the industry, is used in this project to calculate depreciation. Because there is no production in the first and second year, the CAPEX of the first and second year are carried forward until production commences before the depreciation is calculated. Book value at the beginning of the first year of depreciation is the total CAPEX of the asset. Since declining balance depreciation doesn’t consider salvage value in determining the annual depreciation, the asset is depreciated till the end of its useful life and the book value at the end of asset’s useful life is taken to be the asset’s scrap value in this project. The two main types of money – Money of the Day (MOD) and Real Terms money are considered. Money of the Day referred to as nominal money represented by actual notes and coins that its nominal value may remain constant but purchasing power is likely to vary with inflation. Real Term money is an artificial unit, which has constant purchasing power. Therefore a constant inflation rate of 5% per annum is assumed. The same royalty of 10% of gross on exported oil (onshore) under section 10 of PPT Act for convectional crude oil shall be applied and 40% fiscal regime would be used. Base on the above conditions, a cash flow projection over the economic lifetime of project is estimated from which NPVs, IRRs and Pay-Out Periods are estimated with gas price ranging from $0.5/MMBTU to $1.5/MMBTU at $50/bbl. Another major determinant factor for GTL project value is the price of crude oil, which has been escalating lately. Therefore its impact on the GTL project profitability is investigated using $20/bbl, $35/bbl, $50/bbl, $65/bbl and $80/bbl of crude oil. GTL – Di Methyl Ether (DME) DME has similar properties with LPG and consequently would be an innovative clean fuel for various fields; residential, transportation, power generation etc. Nowadays, DME is used mainly as a propellant for spraying cans. Approximately 150,000 tons/year are produced worldwide by a hydration reaction of methanol. In order to use DME as a fuel, it must be produced at low cost in large quantity. The hypothetical GTL-DME plant capacity would be 5000 tons/day and the profitability index and other economic indices are estimated based on different gas prices ranging from 0.5 – 1.5US$/MMBtu and plant distances to the market

ranging from 5000 – 12000km. The economic preconditions are summarized in Table 7. GTL – Methanol Today, world methanol consumption for chemical uses is about 30 million tons per year, using gas at the rate of 1 tcf per year or nearly 3 bscf/day. In a country such as Nigeria, if a world-scale methanol plant were built, it would probably be at least 5000 tons per day in order to take advantage of the well-known effect of scale in lowering capital cost per unit of output. Such a plant would require a gas reserve of roughly 1.37 TCF for 25 years of economic life. In a country like ours with ample and inexpensive gas, capital charges on large plants, as with LNG, dominate the required selling price of the product. The other important item in selling price is shipping cost to reach the market. This alone may be as much as plant operating and maintenance costs, excluding the raw material purchase. Obviously, such plant would be financed very favorably to produce methanol at a cost roughly competitive with the cost of imported methanol and located closer to its market in order to enjoy some freight savings. In this study, the profitability index and other economic indices are estimated based on different gas prices ranging from 0.5 – 1.5US$/MMBtu and plant distances to the market ranging from 5000 – 12000km. The economic preconditions are summarized in Table 8. Liquefied Natural Gas One of the main objectives of this project work is to compare the profitability of GTL (Syncrude, DME and Methanol) with that of LNG, an existing gas monetization technology in Nigeria. It is therefore imperative to investigate the profitability of LNG separately also before comparing it with that of GTL. NLNG project in Bonny with the production capacity of 5.9 million ton per annum and condensate of 4225bbl/day based on 5bbl/mmscf, typical liquid content with train T1 and T2 shall be the basis for all project assumptions and economic analysis. The same project economic lifetime of 25 years is assumed. Furthermore the plant would be in operation for 340 days annually. CAPEX is estimated based on upstream and onshore components. The Upstream component of the project comprises of wells, platform, and pipeline to onshore. Since the project economic lifetime of 25 years, a gas resource of 7.2 Tcf is to be produced and piped to NLNG facility onshore over a 25 year timeframe. Therefore the same Upstream CAPEX of US$1.3 billion published by J. P. Morgan [4] for LNG shall be applied. The same NLNG Onshore CAPEX of US$3.6 billion for base


train T1/T2, which includes Turn-key cost and contingency, cost of four (4) LNG vessels, initial charge of coolants, subtotal plant cost, start up, technical service, insurance, pre-operation expenses, contingency of owner’s cost and initial working capital amongst other things shall be applied. The ratio of capital investment for the first, second and third year of 25%, 35% and 40% respectively shall be applied and the plant construction period shall be 3 years. OPEX is estimated based on offshore and onshore operating expenditure. Offshore OPEX NLNG executed Sales & Purchase Agreements with five buyers located in Europe and Turkey for the Base Project volumes: Enel of Italy, Gas Natural of Spain, Botas of Turkey, Gaz de France of France, and Transgas of Portugal. Presently NLNG T1/T2 receiving facilities are Montoir de Bretagne (ENEL), Bilbao/Huelva/Cartagena/Barcelona/Sagunto (GAS

NATURAL), Huelva/Sines/Cartagena (TRANSGAS), Montoir Terminal (GAZ DE FRANCE and Marmara Terminal (BOTAS) and therefore an average product transport cost of US$0.4/mmBtu shall be applied. The same type of LNG pricing as for Woodside’s Pluto LNG sales into Morth Asian, which is estimated to be US$5.4/mmBtu at an oil price of US$50/bbl shall be applied as the base price. The major determinant factor for LNG project value is the price of LNP product, which has not necessarily been stable. Thus its impact on the LNG project profitability is investigated using US$4.4/mmBtu (at $25/bbl of oil), US$4.8/mmBtu (at $35/bbl of oil), US$5.4/mmBtu (at $50/bbl of oil), and US$6.1 (at $70/bbl of oil). All other economic conditions shall be same with those used in GTL-Syncrude. The preconditions of economic evaluations of LNG is presented in Table 9.


Table 6: Preconditions of economic evaluations of GTL Technology – FT Synthetic Fuel S/N Item Description Estimates Source 1 Product

Quality Specific gravity (T/M3) Heating Value HHV (MMBtu/T)

0.75 43.9

[7]

2 Plant Scale of plant (BBL/D) Plant Economic life (yrs) Plant Location

34 000 (2 Trains) 5406 M3/D (equiv) 25 Niger Delta

EGTL 1 [4, 6]

3 Feedstock (Natural Gas)

Natural Gas consumption (MMBtu/T) Heat Content (Btu/SCF) Total Gas volume required (MMSCF/D) Require Scale of Gas Field (TCF) Natural Gas Price (US$/MMBtu)

73.83 1050 286 2.43 0.5/0.75/1.0/1.5

[7]

4 Total Capital Investment

Turn-key Cost (MMUS$) Contingency of above (MMUS$) Initial Charge of Catalyst (MMUS$) Start-up (MMUS$) Technical Service (MMUS$) Insurance (MMUS$) Pre-operation expenses (MMUS$) Contingency of owner’s cost (MMUS$) Initial working capital (MMUS$) Expenses related to fund procurement Interest during construction period Total Capital Investment (MMUS$) 30% Escalation for inflation and other logistics (MMUS$)

886.86 44.34 27.06 6.8 4.7 1.0 21.9 5.5 30.26 N/A N/A 1,028.42 1,336.94

[2, 4, 7]

Plant Cost Breakdown (estimate only)

ASU & Gas Pretreatment Unit Gasification Unit Fischer Tropsch Unit Product Upgrade

35% 25% 30% 10%

[2,4,6,7]

5 Capital Investment

Net worth ratio (%) Ratio of capital investment 1st year (%) Ratio of capital investment 2nd year (%) Ratio of capital investment 3rd year (%)

100 25 35 40

[2, 3, 7]

6 Plant Construction

EPC Period 3 [2, 3, 7]

7 Operations

Plant operation in a year (Days/Year) Load Factor 1st year (%) Load Factor 2nd year (%) Load Factor 3rd year (%) Utility cost (electricity) Utility cost (cooling water) Other Cost [Utility(process) & Chemicals] US$/bbl-product Total utility cost US$/bbl-product (excluding Feedstock cost)

340 90 95 100 Self-support Self support 6.00 6.00

[4, 7]

8 Depreciation Double Declining Balance

9 Royalties on Export 10% of gross Under section 10 of PPT Act

10 Fiscal Regime 40% of Taxable income


Table 7: Preconditions of economic evaluations of GTL - DME S/N Item Estimates Source

1 Product Quality Specific gravity (T/M3)

Heating Value HHV (MMBtu/T)

0.74

29.9

[1, 7, 21]

2

Plant

Scale of plant (T/D)

Plant Economic life (yrs)

Plant Location

5000

25

Niger Delta

3

Feedstock

(Natural Gas)

Natural Gas consumption (MMBtu/T)

Heat Content (Btu/SCF)

Total Gas volume required (MMSCF/D)

Require Scale of Gas Field (TCF)

Natural Gas Price (US$/MMBtu)

43.49

1050

207

1.4

0.5/0.75/1.0/1.5

[1,7]

4

Total Capital

Investment

Turn-key Cost (MMUS$)

Contingency of above (MMUS$)

Initial Charge of Catalyst (MMUS$)

Start-up (MMUS$)

Technical Service (MMUS$)

Insurance (MMUS$)

Pre-operation expenses (MMUS$)

Contingency of owner’s cost (MMUS$)

Initial working capital (MMUS$)

Expenses related to fund procurement

Interest during construction period

Total Capital Investment (MMUS$)

30% Escalation for inflation and other logistics

489.5

24.5

22.0

9.0

6.3

1.0

12.6

5.1

16

N/A

N/A

586

738.4

[7, 21]

5

Capital Investment

Net worth ratio (%)

Ratio of capital investment 1st year (%)

Ratio of capital investment 2nd year (%)

Ratio of capital investment 3rd year (%)

100

25

35

40

[2, 3, 7]

6 Plant Construction EPC Period 3 [2, 3, 7]

7

Operations

Plant operation in a year (Days/Year)

Load Factor 1st year (%)

Load Factor 2nd year (%)

Load Factor 3rd year (%)

Utility cost (electricity) US$/ton-product

Utility cost (cooling water) US$/ton-product

Utility cost (process) US$/ton-product

Chemicals US$/ton-product

Total utility cost US$/ton-product

340

90

95

100

2 (0.028US$/KWh)

4.24

(0.028US$/KWh)

0.04(0.028US$/KWh

)

1.94

8.22

[7, 21]




11 Freight Cost 2.5US$/1000km/ton (0.0836US$/1000km/MMBtu)

12 Distance 5000km (base case)


Table 8: Preconditions of economic evaluations of GTL - Methanol S/N Item Estimates Source

1 Product Quality Specific gravity (T/M3)

Heating Value HHV (MMBtu/T)

0.79

21.5

[1, 7]

2

Plant

Scale of plant (T/D)


Plant Location

5000

25

Niger Delta

3

Feedstock

(Natural Gas)

Natural Gas consumption (MMBtu/T)




Natural Gas Price (US$/MMBtu)

33.89

1050

162

1.37

0.5/0.75/1.0/1.5

[1, 7]

4

Total Capital Investment

Turn-key Cost (MMUS$)

Contingency of above (MMUS$)

Initial Charge of Catalyst (MMUS$)

Start-up (MMUS$)

Technical Service (MMUS$)

Insurance (MMUS$)

Pre-operation expenses (MMUS$)

Contingency of owner’s cost (MMUS$)

Initial working capital (MMUS$)

Expenses related to fund procurement

Interest during construction period

Total Capital Investment (MMUS$)

30% Escalation for inflation and other logistics

423

21.2

4.4

6.3

6.3

1.0

12.3

3.0

20

N/A

N/A

498.2

647.66

[1, 7]

5

Capital Investment

Net worth ratio (%)




100

25

35

40

[2, 3, 7]


7

Operations

Plant operation in a year (Days/Year)




Utility cost (electricity) US$/ton-product

Utility cost (cooling water) US$/ton-product

Utility cost (process) US$/ton-product

Chemicals US$/ton-product

Total utility cost US$/ton-product

340

90

95

100

3.65 (0.028US$/KWh)

2.12 (0.028US$/KWh)

0.03(0.028US$/KWh)

1.41

7.21

[1, 7]




11 Freight Cost 3.914US$/1000km/ton (0.182US$/1000km/MMBtu)

12 Distance 5000km (base case)


Table 9: Preconditions of economic evaluations of LNG S/N Item Estimates Source

1 Product Quality Heating Content (Btu/scf)

Carbon Efficiency

Conversion Factor

1050

92%

1 mt/a~48.699bcf

[1, 4]

Product Price LNG

Condensate

5.4US$/MMBTU

50US$/BBL

[4]

2

Plant

Scale of plant

LNG (MT/A)

Condensate (BBL/D)


Plant Location

5.9 (Train T1/T2)

4225 (5bbl/mmscf)

25

Niger Delta

NLNG

3

Feedstock

(Natural Gas)

Natural Gas consumption (scf/T)




142.86

1050

850

7.2

4 CAPEX

Upstream Capex

Downstream Capex

U$1.3b

U$3.6b

NLNG

5

Capital Investment

Net worth ratio (%)




100

25

35

40

[2, 3, 7]

OPEX

Offshore Opex

Onshore Opex

US$0.2/MMBTU

US$0.2/MMBTU

[4]

Operation operation in a year (Days/Year)




340

90

95

100

[2, 3, 7]


7

8 Depreciation Double Declining Balance Double Declining Balance



11 Transportation Freight Cost U$0.4/MMBTU [1, 4]


Results and Discussion GTL Syncrude GTL-Syncrude cash flow projection was prepared with the economic conditions in Table 6 on a spread sheet assuming an average price of US$50/bbl for Diesel, Kerosene, and Naphtha as the base price. The GTL-Syncrude project annual real term cash flow is shown in Figure 2. Investor’s cumulative cash flow both in real terms and money of the day is shown in Figure 3 with undiscounted real term cash surplus of US$4.19 billion. GTL-Syncrude investor’s NPV is US$7.18 million, discounted at 10% as shown in Figure 4. The Real Terms Earning Power of the project at the base price is 18.33% as can be seen in Figure 5, which exceeds that of a risky exploration project of about 15% [9].

-500-400-300-200-100

0100200300400500

Cas

hflo

w (M

MU$

RT)

1 3 5 7 9 11 13 15 17 19 21 23 25

Years

Government Annual Cashflow Investor's Annual Cashflow Figure 2: GTL- Syncrude Project Annual Real Terms Cash flow @ US$50/bbl of Oil Table 10 shows the estimated DPIR at various discount rates. It expresses the GTL – Syncrude investment efficiency at various discount rates. The implication is that an investment proposal is rejected at any discount rate that gives negative DPIR. Thus GTL- Syncrude investment proposal shall be rejected at about 20% discount rate. Table 10: GTL –Syncrude Profitability Indicators @ US$50/bbl of Oil

-2000

0

2000

4000

6000

8000

10000

Cum

Cas

flow

(MM

US$)

1 3 5 7 9 11 13 15 17 19 21 23 25

Years

RT Cum Cashflow MOD Cum Cashflow Figure 3: GTL- Syncrude Investor’s Undiscounted Cash flow Surplus

-2000

-1000

0

1000

2000

3000

4000

5000

Cum

. Cas

hflo

w (M

MU$

RT)

1 3 5 7 9 11 13 15 17 19 21 23 25

Years

Cum NPV @ 10% Discount Rate Undiscounted Cash Surplus Figure 4: GTL-Syncrude Investor’s Cumulative Real Terms Cashflow @ US$50/bbl of Oil

-1000

-500

0500

1000

1500

2000

2500

30003500

4000

4500

0 0.05 0.1 0.15 0.2 0.25 0.3 0.35 0.4

Discount Rates

Cum

mul

ativ

e C

ashf

low

(MM

US$

RT)

Figure 5: GTL-Syncrude Investor’s NPVs @ various Discount Rates Table 11 shows project benefits (investor and government’s shares) and expenditures (CAPEX and OPEX) on percentage basis of project revenue at various discount rates. This gives a slightly different view and may give further insight into the project economics particularly when a constant oil price is used. It is clear that the main impediment to high earning powers is the CAPEX which takes the greater proportion at high discount rates. As the government take remains pretty constant (averaging 32.44% of project revenue at the discount rates shown), the difference is largely balanced by the investor’s share, which reduces accordingly.

Discount Rate 0 10% 15% 20% NPV Revenue

MMUS$ RT

13207.30

4180.22

2742.09

1929.26

NPV Project MMUS$

RT 8537.46 2032.9

8 1054.0

3 529.45 NPV Government

MMUS$ RT 4413.66

1341.54 864.38 598.95

NPV Investor

MMUS$ RT 4123.80 691.44 189.65 -69.50

NPV OPEX MMUS$

RT 3332.90 1054.8

9 691.97 486.86

NPV CAPEX MMUS$

RT 1336.94 1092.3

5 996.08 912.96

DPIR MMUS$

RT 3.08 0.63 0.19 -0.08


Table 11: GTL - Syncrude Profitability Indicators – on % basis

It should be noted that the high royalty and tax rate applied in this project produce a significant boost to the government cash flow – even in the first year of production when the investor’s cash flow is still heavily negative. This suggests that the economic result for the investor will be very strongly dependent also on the level of the royalty and other fiscal terms put in place by the host government as shown in Table 12. Although oil price invariably has an over riding effect because it controls the project economics. However sensitivity to fiscal terms depends on the relative levels of royalty and tax rate. Table 12: GTL – Syncrude Profitability Indicators based on Oil Price of 50U$/MMBTU and gas price of US$0.75/MMBTU at various Fiscal Regime

However, the main determinants of project value are the oil and gas prices. Therefore, Tables 13 and 14 show the profitability indicators derived based on different oil and gas prices range from US$20/bbl to US$80/bbl and US$0.25/MMBTU to US$1.5/MMBTU respectively. The economics of GTL – Syncrude improve as the oil price and refining margin increase as shown in Table 13. When the oil price is US$35/bbl, GTL becomes economical with positive NPV and relatively high earning power.

Table 13: GTL - Syncrude Profitability Indicators based on Gas Price of 0.75U$/MMBTU @ various prices of Crude Oil

Table 14: GTL – Syncrude Profitability Indicators based on Oil Price of 50U$/MMBTU @ various prices of Natural Gas

Though high maximum exposure (money at risk if the project were to be abandoned at the pay – as – you – go time) and long pay out time may be discouraging. The potential return of GTL – Syncrude at higher oil prices, say US$40/bbl and above is too large to ignore. Based on this analysis, Gas – to – Liquids Technology (Syncrude) would be economically feasible when applied to typical offshore of Nigerian large gas resources at Oil price above US$35/bbl. GTL fuels used for transport should attract in theory a premium price as they have been shown to reduce vehicle exhaust emissions [4]. The extent of that premium will be dependent on the outlook of environmental legislation in key markets. GTL – DME The major determining factors for economic feasibility of GTL-DME are the present and future prices of Natural Gas and DME or LPG, which is the alternative fuel to DME. The investor’s NPV at 10% is US$281.89 million and the estimated real terms earning power based on the base prices of DME and Feedstock is 16.26%. This implies that GTL – DME is viable at the cost of capital less than 16.26% discount rate. This is also favourably compared with that of a risky oil exploration of about 15%.

Discount Rate 0 5% 10% 15% NPV Government % 33.42 32.74 32.09 31.52 NPV Investor % 31.22 24.81 16.54 6.92

NPV OPEX % 25.24 25.24 25.24 25.24

NPV CAPEX % 10.12 17.22 26.13 36.33

Total % 100.00 100.00 100.00 100.00

Fiscal Regim

e % RTEP IRR

PAY OUT TIME (YRS)

NPV @ 10%

(MMUS$ RT)

Max Exposure (MMUS$ MOD)

40 18.33 24.24 7.31 691.44 -1143.07

35 19.56 25.53 7.02 806.84 -1130.65

30 20.75 26.79 6.77 922.32 -1118.23

25 21.93 28.03 6.55 1037.76 -1105.81

20 23.09 29.24 6.35 1153.20 -1093.39

Crude Oil

US$/bbl RTEP IRR

PAY OUT TIME (YRS)

NPV @ (MMUS$ RT)

Max Exposure

($ mm MOD)

20 No Break Even -662.956 -1328.89

35 10.19 15.70 9.46 14.24 -1235.98

50 18.33 24.24 7.31 691.437 -1143.07

65 25.66 31.95 4.10 1368.633 -1050.15

80 32.65 39.29 2.90 2045.829 -957.24

Gas Price

US$/MMBTU RTEP IRR

PAY OUT TIME (YRS)

NPV @ 10%

(MMUS$ RT)

Max Exposur

e (MMUS$

MOD)

0.25 20.78 26.82 5.26 912.7426 -1112.70

0.50 19.56 25.54 7.00 802.09 -1127.88

0.75 18.33 24.24 7.31 691.437 -1143.07

1.00 17.07 22.93 7.64 580.7837 -1158.25

1.50 14.49 20.21 8.49 359.4778 -1188.61


The GTL – DME investment efficiency is expressed in the estimated DPIR at different discount rates shown in Table 13. The implication of this is that GTL-DME viability becomes uncertain at discount rate of 20% and should be rejected. From Table 14, it is evident that the fiscal policy of the host government plays a vital role in the viability of GTL project as her takes is relatively constant at various discount rates. Table 13: GTL-DME Productivity Indicators at DME Price of US$6/MMBTU


MMUS$ RT

6968.80

2205.68

1446.86

1017.97

NPV Project MMUS$

RT 4156.1

5 945.85 466.06 210.74 NPV Government

MMUS$ RT

2194.49 663.97 426.91 295.28

NPV Investor

MMUS$ RT

1961.66 281.89 39.15 -84.53

NPV OPEX MMUS$

RT 2074.2

5 656.52 430.65 303.00

NPV CAPEX MMUS$

RT 738.40 603.31 550.14 504.23

DPIR 2.657 0.467 0.071 -0.168

Table 14: GTL-DME Profitability Indicator on percentage basis

Discount Rate 0% 5% 10% 15%

NPV Government % 31.4

9 30.7

8 30.10 29.51

NPV Investor % 28.1

5 21.4

3 12.78 2.71

NPV OPEX % 29.7

6 29.7

6 29.76 29.76

NPV CAPEX % 10.6

0 18.0

2 27.35 38.02

Total 100 100 100 100

From the LPG price sensitivity analysis, GTL- DME becomes economically viable when LPG price is US$5/MMBTU and above at gas based price of US$0.75/MMBTU as shown in Tables 15. From this analysis GTL – DME looks promising in term of economic viability and could be introduced at price lower than that of LPG and even much lower if Government takes (in terms of royalty and taxes) can be reduced. Table 15: GTL-DME Profitability Indicator at various prices of Natural Gas

Natural Gas Price (US$/MMBtu) RTEP IRR

PAY OUT TIME (YRS)

NPV @ 10% ($ mm RT)

Max Exposure ($ mm MOD)

0.50 17.92 23.82 7.41 362.09 -634.04

0.75 16.26 22.08 7.89 281.89 -645.04

1.00 14.56 20.29 8.47 201.68 -656.05

1.25 12.81 18.44 9.18 121.48 -667.05

1.50 10.98 16.52 10.08 41.27 -678.05

It would be a good substitute for LPG when the feedstock gas price is in a range of US$0.25 to US$1.5/mmBtu and could be used as a new clean fuel for various fields; residential, transportation, power generation, etc as LPG. This may be a deterrent force to ever increasing LPG contract prices. However, the possibility of DME to practically substitute LPG in term of quality must be confirmed probably through combustion tests before its introduction into the market. GTL-Methanol The economic feasibility is estimated based on the present and future selling price of natural gas in British thermal units – 0.5, 0.75, 1, 1.25 and 1.5US$/MMBtu. What is important in the final analysis is the Btu cost delivered to the customer. The RTEP is 10.53% and the cumulative cash flow discounted at 10% is US$19.45 million. From the estimated DPIR at various discount rates and Methanol base price of US$6/MMBTU as shown in Table 16, GTL-Methanol investment proposal should be rejected at 15% discount rate. Table 17 shows GTL-Methanol benefits and expenditure on percentage basis of project revenue at various discount rates. Table 16: GTL-Methanol Productivity Indicator @ 0.75US$/MMBtu of Natural Gas


MMUS$ RT

5011.01

1586.03 1040.38

731.99

NPV Project MMUS$

RT 2335.7

6 415.11 136.88 -6.46 NPV Government

MMUS$ RT

1334.88 395.65 251.97

172.81

NPV Investor

MMUS$ RT

1000.89 19.45 -115.09

-179.28

NPV OPEX MMUS$

RT 2027.5

8 641.75 420.96 296.18

NPV CAPEX MMUS$

RT 647.66 529.17 482.54 442.27

DPIR 1.545 0.037 -0.239 -0.405

Table 17: GTL-Methanol Productivity Indicators on percentage basis

Discount Rate 0% 5% 10% 15% NPV Government % 26.64 25.77 24.95 24.22

NPV Investor % 19.97 11.78 1.23 -11.06

NPV OPEX % 40.46 40.46 40.46 40.46

NPV CAPEX % 12.92 21.98 33.36 46.38

Total 100 100.0

0 100.00 100.00

The profitability indicators derived based on different gas prices ranging from 0.5 – 1.5 US$/MMBtu are shown in Tables 18. At a very low gas price of 0.5US$/MMBtu, GTL-Methanol is highly economical with earning power of 12.17% and NPV discounted at 10% of US$81.96 million.


However as the price of gas improved, the economic feasibility of GTL-Methanol becomes uncertain. When the gas price exceeds 1US$/MMBtu, the Btu cost of Methanol must exceed 6.5US$/MMBtu to be economical. Table 18: GTL-Methanol Profitability Indicator @ various prices of Natural Gas

Natural Gas

Price (US$/MM

Btu) RTEP IRR

PAY OUT TIME (YRS)

NPV @ 10% ($ mm RT)

Max Exposure ($ mm MOD)

0.50 12.17 17.7

8 9.47 81.96 -588.45

0.75 10.53 16.0

5 10.34 19.45 -597.03

1.00 8.80 14.2

4 11.46 -43.05 -605.60

1.25 6.96 12.3

1 12.96 -105.56 -614.18

1.50 4.98 10.2

3 15.10 -168.07 -622.75

In a country like ours with ample and inexpensive gas, a distress gas price of 0.25US$/MMBtu may be applied. This would reduce the delivered Btu level for methanol to as low as 5.0US$/MMBtu. Also the effect of the royalty and tax rate applied here on the project is too huge to be ignored. For a large plant such as this, if we assume no financing by World Bank but commercial financing rate of 70% debt payable over ten years at 8% and 20% before tax on equity where there are no taxes for 10 years as plant depreciation shelters book profit, the proposed GTL-Methanol project could compete with gasoline for transport fuel or with kerosene when used for domestic fuel. The respective retail price levels for gasoline and kerosene markets are 7.0US$/MMBtu and 7.5 – 11US$/MMBtu. Even at gas price of 0.75US$/MMBtu, GTL-Methanol would still be able to stay in business at about 6.0US$/MMBtu delivered to terminal or push consistently below it. In Nigeria, where kerosene market has a less efficient distribution system, methanol stove could be introduced and from the analysis above, methanol could be available as alternative to kerosene for domestic fuel within the range of 0.4 to 0.7US$/gallon (N54/gallon). It should be noted that distributor can take methanol from a low cost terminal with a gasoline truck and consumer can take it away in a jerry can. Methanol been an economical energy carrier, it could also be an excellent choice for distributing power generation out to the rural population. Therefore the opportunity for methanol as a fuel is apparent, especially when it is considered that methanol, for certain uses, has premium properties justifying a higher Btu cost. Economics of LNG versus GTL

Table 19 summarizes economic comparison between LNG project and various GTL projects. LNG has a net profit of US$13.95 billion at zero discounted rate, a discounted profit to investment ratio of 2.85 and an investor’s real terms earning power of 17.21%. By comparison, GTL Syncrude, DME and Methanol has net profit of US$4.12 billion, US$1.96 billion and US$1.00 billion, a discounted profit to investment ratio of 3.08, 2.66 and 1.55 and an investor’s real terms earning power of 18.33%, 16.28% and 10.53% respectively. Using investor’s real terms earning power criteria, GTL-Syncrude is the best investment proposal closely followed by LNG and GTL-DME. GTL-Methanol is the least economical investment proposal. The present value and Discounted Profit-to-Investment Ratio profiles prepared from Table 19 are shown in Figures 6a&b and 7 respectively. From the present value profiles shown in Figure 6a, LNG has the highest investor net present value of US$458 million at 15% discount rate. However, bringing the present value profile of LNG and GTL-Syncrude closely as shown in Figure 6b, the two projects have the same investor’s net present value at discount rate of 16.84%. This implies that LNG would give higher profit if the cost of capital is less than 16.84%, while GTL-Syncrude would be a better investment proposal if the cost of capital is higher than 16.84%.

-1000.00

2000.00

5000.00

8000.00

11000.00

14000.00

0 5 10 15 20 25

Discount Rate (%)

Inve

stor

's N

PVs

(MM

US$

RT)

LNG GTL- Syncrude GTL- DME GTL - Methanol Figure 6a: Present Value Profiles for LNG and GTL Projects

-200.00

-100.00

0.00

100.00

200.00

300.00

400.00

500.00

600.00

15 16 17 18 19 20 21

Discount Rates

Inve

stor

's N

PVs

(MM

US$

RT)

LNG GTL-Syncrude


Figure 6b: Present Value Profiles for LNG and GTL-Syncrude The Discounted Profit-to-Investment Ratio profile (DPIR) shown in Figure 7 gives whole picture of the investment efficiency of LNG and GTL investment proposals. The DPIR is a modification of NPV that is used to select projects under conditions of limited capital. It includes all advantages of NPV in addition to providing a measure of profitability per dollar invested. Unlike profit-to-investment criterion, DPIR reflects the time rate pattern of income from the project and thus ranks projects properly to assure maximization of profits. The decision is to maximize DPIR. Therefore using this important profitability criterion shown in Figure 7, GTL-Syncrude could be ranked first closely followed by LNG and GTL-DME in that

order while GTL-Methanol is the least profitable investment proposal.

-1.00

-0.50

0.000.50

1.00

1.50

2.002.50

3.00

3.50

0 5 10 15 20 25

Discount Rate (%)

Disc

ount

ed P

rofit

-to-In

vest

men

t Ra

tio

LNG GTL - Syncrude GTL - DME GTL - Methanol Figure 7: Discounted Profit-to-Investment Ratio Profiles for LNG & GTL

Table 19: The Economics of LNG versus GTL

LNG GTL-Syncrude GTL-DME GTL-Methanol

Discount Rate

(%)

Investor's NPVs

(MMUS$ RT) DPIR

Investor's NPVs

(MMUS$ RT) DPIR

Investor's NPVs

(MMUS$ RT) DPIR

Investor's NPVs

(MMUS$ RT) DPIR

0 13954.74 2.85 4123.80 3.08 1961.66 2.66 1000.89 1.55 5 5751.78 1.30 1736.08 1.44 791.44 1.19 312.85 0.54

10 2171.32 0.54 691.44 0.63 281.89 0.47 19.45 0.04 15 458.54 0.13 189.65 0.19 39.15 0.07 -115.09 -0.24 20 -420.09 -0.13 -69.5 -0.08 -84.53 -0.17 -179.28 -0.41

RTEP 17.21 18.33 16.28 10.53 IRR 23.07 24.24 22.08 16.05 POT 7.6 7.31 7.89 10.34


Conclusions The interest in GTL technology is increasing in the light of the growing concern on strong spot of oil prices, global warming and resulting climate change. One of the most promising routes to produce clean fuels is the Fischer Tropsch synthesis, wherein natural gas is chemically converted into important liquid fuels. Though there has been a great deal of interest and activity in the GTL technology, commercial development has been piecemeal and slow. The major draw back of the technology is the higher capital costs of processing plants relative to conventional fuels. Nowadays, the most common approach involves the use of slurry reactors to produce a waxy product that is then hydrocracked to form diesel. This approach gives the highest carbon efficiency (typically about 75%). However, the overall energy efficiency remains low (typically 60% to 65%). From the economic analysis of Gas – to –Liquids carried out in this project work, the following conclusions could be drawn:

i. Gas – to – Liquids technology with the principal interest in the production of diesel would be economically feasible when applied to a typical offshore Niger Delta large resource at oil prices of above US$35/bbl and feedstock gas price in the range of US$0.25-1.5/mmBtu.

ii. Gas – to – Liquids technology economics

improve as the oil price and refining margin

iii. increase. Also the government takes in form of taxes and royalty applied in the analysis is too

iv. big (about 34% cost of product) to be ignored. This implies that GTL investment proposal looks more promising if a preferential tax treatment could be applied.

v. GTL-DME economics looks encouraging and could be introduced at a price lower than that of LPG, but to secure a certain volume of demand for the product must be the first consideration before a DME project is launched. Potential DME customers are believed to be those currently consuming LPG delivered by lorry trucks from LPG import terminals and those shifting fuels from petroleum based ones.

vi. GTL-Methanol is hardly viable in economic terms except in the situation of low feedstock gas price of US$0.25-0.5/mmBtu and preferential tax treatment.

vii. LNG requires greater capex for a similar gas reserve size and has a longer payback period. However LNG would give higher profit if the cost of capital is less than 16.84%.

viii. GTL-Syncrude with principal interest in diesel production would be a better investment proposal if the cost of capital is between 16.84% and 18.33%. At higher oil prices, say US$40/bbl and above, the potential superior return of GTL over LNG is too large to ignore.

Therefore, from overall assessment of GTL Technology, the profitability of LNG and GTL (Syncrude and DME) is very close, with GTL having a potential superior return at high oil prices and preferable under conditions of limited capital Technological wise, GTL is more technologically complex and far mature than LNG and therefore carries greater technological and operational risk. However it is no accident that most companies with GTL plans all have LNG expertise. Since LNG and GTL draw from the same pool of contractors and vendors, companies with LNG experience can leverage their existing relationships when building GTL facilities. From environmental standpoint, FT diesel becomes the most promising fuel and expected to be spotlighted in the future as the quality requirement for diesel fuel and automotive emission are strengthened further. GTL and LNG are compatible and in a country of ours where LNG production already exists, GTL could be used as an adjunct to LNG to monetize “leftover” gas that doesn’t merit a standalone new LNG train. Also GTL and LNG serve two completely separate market; in a country like ours where there is ample gas resource, GTL would not only complement the already existing LNG in monetizing about 2bcf of gas been flared daily and 120 tcf proven and uncommitted gas reserves but also provide the country an opportunity to enjoy direct exposure to oil price upsides. Recommendations This project work has shown that FT diesel is promising in the diesel market, while DME is promising in the industrial fuels market. For practical introduction of these GTL products, however, the question is how a certain volume of demand can be developed. In the light of this, the followings are recommended for the smooth uptake of GTL Technology in Nigeria:


i. Gas reserves that can effectively serve GTL plants through out their economic life should be secured

ii. Improving the gasification and gas cleaning technologies to achieve higher energy efficiencies would certainly reduce the costs. Pressurized gasification can result in large cost reductions, as higher throughputs are possible with same scale installations, and because compression of syngas from atmospheric pressure to FT synthesis pressure is extremely energy intensive.

iii. Reduction of the synthesis gas costs could be accomplished by a decrease of steam/carbon and oxygen/carbon ratios in the feedstock.

iv. Preferential Tax treatment in GTL investment would encourage investors in Oil and Gas industry to embark on the establishment of GTL Technology in Nigeria.

v. A distress gas price in the range of 0.25-0.5US$/MMBTU would also encourage investors

vi. GTL-Diesel is been used in South Africa, U.S. and Europe but none in Nigeria. Thus it is imperative to confirm its quality superiority over the conventional diesel, secure the base of demand and create demand for the future before GTL-Diesel introduction in Nigeria.

vii. A certain volume of demand for the DME product must be secured first before a DME project is launched.

References

1) Duncan Seddon, (2006), Gas Usage & Value: The Technology and Economics of Natural Gas Use in the Industry, PennWell Corporation, South Sheridan Road, Tulsa, Oklahoma

2) Dennis Denney (April 2005), GTL: “An Attractive Route for Gas Monetization?” Journal of Petroleum Technology, page 65 – 66

3) Kroschnitz I., Howe-Grant M. (1996), Kirk-Othmer Encyclopedia of Chemical Technology, 4th Edition, Wiley & Sons, New York

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