Commercialization of Marginal Gas Fields

Transcription

1 Public Disclosure Authorized Public Disclosure Authorized Public Disclosure Authorized Public Disclosure Authorized Commercialization of Marginal Gas Fields Masami Kojima Introduction Natural gas reservoirs are plentiful around the world, but many of them currently seem too small, or too remote from sizable population centers, to be developed economically. Furthermore, gas associated with liquid hydrocarbons is often flared for the same reason. According to the United States Department of Energy, a total of 14.8 trillion cubic feet (tcf) of gas was flared or reinjected worldwide in 1995, 4.4 tcf of this amount was in Africa, and 1.2 tcf in Latin America and the Caribbean. In western and southern Africa (excluding Nigeria), there are eight gas fields with reserves ranging between 0.5 and 1.0 tcf, another eight between 0.25 and 0.5 tcf, and over 85 fields with reserves of less than 0.25 tcf. A key challenge, and the subject of this Note, is identifying commercial processes that make marginal gas reservoirs viable. Apart from the economic advantages, such use of gas brings local and global environmental benefits. The World Bank and the Energy Sector Management Assistance Programme (ESMAP) provide assistance to client countries that are seeking to commercialize production of natural gas. In the Africa Gas Initiative (AGI), for example, the Bank and ESMAP supports efforts to create local and regional markets for natural gas and liquefied petroleum gas (LPG) in West A f r i c a. The AGI has focused mainly on finding uses for gas, in traditional applications such as power generation, and on addressing market imperfections such as regulations, price control and subsidies that inhibit investment. In many regions, howeve r, traditional market-promoting efforts will not be enough to make marginal fields commercial. Promising technologies for using and converting gas will have to be promoted in parallel. ESMAP carried out a study to address the readiness and cost of technologies that could render marginal gas fields commercial. The technologies that were examined were: Use of gas for direct reduction (DR) of iron oxides to produce metallic iron for use in steelmaking. Manufacture of carbon black and hydrogen. Carbon black is used predominantly in the production of vehicle tires. Stand-alone methanol plants. Methanol, which can be made from gas, is used in the synthesis of chemicals, particularly formaldehyde, and methyl tertiary butyl ether (MTBE), which is used as a high octane gasoline blending component. The novel technology of floating, production, storage, and off-loading (FPSO) methanol plants for small, offshore fields. No.16 Jan 1999 The World Bank Group Energy, Mining & Telecommunications Finance, Private Sector and Infrasturcutre Network Masami Kojima (mkojima@worldbank.org) is an Environmental/Refining Specialist who joined the Oil and Gas Unit of the World Bank in She has been working primarily in the area of air pollution abatement. She joined the Bank from UOP. Prior to UOP she was Associate Professor of Chemical Engineering at the University of Cape Town in South Africa.

2 2 Commercialization of Marginal Gas Fields The emerging process of gas-to-liquids (GTL) conversion of natural gas to synthetic fuels (synfuels). Conversion of natural gas to dimethyl ether (DME), a clean-fuel substitute for diesel. Gas-to-olefins (GTO) and methanol-to-olefins (MTO). These processes involve converting natural gas to methanol, followed by converting methanol to light olefins, such as ethylene and propylene (petrochemical feedstocks). Stand-alone ammonia plants or a combined ammonia-urea complex. Ammonia is primarily used for production of fertilizers, and urea is a key nitrogenous fertilizer. Economic analysis was carried out for the processe s shown in Table 1. The approach adopted was to compute the gas va l u e, viz., the maximum gas price that can be charged at the burner tip for a given process that will permit the project to remain competitive in the market. The gas value thus includes the transportation cost, if any, to the burner tip (n e t b a ck va l u e is the field value, i.e. exclusive of transportation). The gas values were computed as the values that would result in a zero net present value for the process assuming a discount rate of 15 percent. The calculated gas values, and therefore the ranking of the technologies considered, are highly sensitive to the discount rate of interest used, and to the capital expenditures and price of the product in question. The values reported are therefore intended as first-order estimates only. The economic analysis was used to suggest which options should be excluded from further consideration and which should be pursued through more detailed feasibility studies. The assumptions used in the study are listed in Table 2. The capital cost for each process was obtained from technology suppliers. Product prices were based on historical world prices. In Table 1. Field Sizes Examined Total gas consumption Technology Plant production per day in tcf in 25 years Direct reduction of iron ore 2900 t 0.3 Carbon black 120 t 0.06 Dimethyl ether (DME) 4300, 1800 t 1.6, 0.7 Methanol, land-based 2500,1500, 600 t 0.7, 0.4, 0.2 Methanol, floating production 1500, 900, 600 t 0.4, 0.25, 0.15 Ammonia 1800, 1000 t 0.5, 0.3 Ammonia/urea 3100, 1700 t 0.6, 0.3 Gas to olefins (GTO) 2400, 1500, 1200 t* 3.0, 2.0, 1.5 Gas to liquids (GTL), land-based 20000, 10000, 5000 bbl 1.7, 0.85, 0.4 GTL, floating production 10000, 5000 bbl 0.85, 0.4 t = metric tons; bbl = barrels; t* = metric tons of ethylene

3 Energy Issues 3 Table 2. Assumptions in Economic Calculations Construction period Years of operation 25 3 years Number of operating days 340 per annum Discount rate 15% Dependence of capital cost on plant size Offsites Ratio of capital costs raised to a power of % of inside battery limit capital cost Localization factor Varied between 1.0 and 2.0 Maintenance cost Operational expenses Product price Obtained from technology suppliers as a percentage of capital cost Obtained from technology suppliers Based on historical world prices; for DME and synfuel, historical world price of diesel adjusted for quality the case of DME to be used as a diesel substitute, and synfuel which is produced only in small quantities in South Africa and Malaysia, the world price of diesel adjusted for fuel quality was estimated. On account of economies of scale, the gas value increases with increasing plant size in all cases. Sensitivity analysis was carried out by varying the capital cost and product price. The results may be found in the ESMAP publication, C o m m e rc i a l i z ation of Marginal Gas Fi e l d s, Report No. 201/97 (December 1997). The localization factor is the factor applied to benchmark U.S. Gulf Coast capital costs to estimate local costs. In remote areas, the localization factor is typically 1.3 or higher. Process Descriptions Conversion of natural gas to synthesis gas In all the processes where natural gas is converted to higher value chemicals, the first step is the production of synthesis gas (syngas), a mixture of carbon monoxide and hydrogen. Syngas production is very capital intensive and accounts for over half of the total capital cost in most processes. There is much research and development underway to reduce the cost of syngas production. An example of an area under investigation is the development of a ceramic membrane which would allow oxygen ions to permeate through the membrane to react with natural gas directly to form syngas, thereby eliminating the need for expensive air separation. Direct reduction (DR) In direct reduction, iron oxides are reduced to iron, called direct reduced iron (DRI), for steel production. DR uses natural gas as the only energy carrier and reducing medium. The study considered two d i fferent processes. One is Mildrex, which is the most commonly used DR process and uses lumpy or pelletized iron ore. Nearly 50 Mildrex modules are in operation or under construction worldwide. The other is a new process (for example, Finmet and Circored) which can use iron ore fines directl y. The quality of the iron ore (i.e. the iron content; the amount of metallic residuals such as copper, nickel and cobalt; and the amount of mineral oxides such as silica, magnesia, alumina and titania) has a marked effect on process economics, but these factors were considered outside the scope of the present study which focused only on the cost d i fferential between iron ore fines and pelletized

4 4 Commercialization of Marginal Gas Fields iron ore. DRI typically oxidizes upon exposure to a i r, and hence the DR plant has to be located close to a steel manufacturer. Carbon black A novel process developed by Kværner Engineering was examined. The process uses a high temperature plasma torch to convert natural gas directly to carbon black and hydrogen. Pyrolysis (chemical decomposition occurring as a result of high temperature) is said to be nearly 100 percent efficient. Consideration has to be given to the distance between the carbon black plant and the hydrogen user. Dimethyl ether (DME) DME is a clean substitute for diesel: it is free of s u l f u r, and its combustion in a diesel engine substantially reduces the emissions of hydrocarbons, oxides of nitrogen, and particulate matter. Haldor Tops e has developed a process for converting syngas directly to DME. However, DME is a gas at ambient temperature and pressure, and needs to be stored and transported under pressure, similar to LPG. The use of DME as an alternative transportation fuel would thus require a new fuel distribution system as well as minor engine modifications. Methanol Methanol is produced from syngas, and is used in the manufacture of formaldehyde, MTBE, and acetic acid. It is also an intermediate in gas-toolefins (GTO). A floating production methanol plant is technically viable and was considered in this study. Ammonia and ammonia/urea Hydrogen from syngas is reacted with nitrogen from air to form ammonia. 85% of world production of ammonia is used in making fertilizers, the most important of which is urea. Since ammonia is a gas and difficult to transport, a combined ammonia/urea complex was also considered. Gas to olefins (GTO) G TO is a new technology which converts syngas to methanol and methanol to light olefins, primarily ethylene and propylene. Ethylene is the larg e s t volume petrochemical produced worldwide. GTO is an alternative to naphtha and gas cracking. Because these light olefins are gaseous, the GTO plant should be located next to a polyolefins plant. Gas to liquids (GTL) G T L is an emerging technology area which has generated a great deal of interest. With the exception of Mobil s methanol-to-gasoline, all GTL processes convert syngas to liquid fuels using F i s c h e r- Tropsch synthesis. The products include ultra-high quality diesel and specialty waxes. S h e l l s 12,500 barrels per day (b/d) unit in Malaysia has been operating since The diesel from this plant is exported to California. Sasol in South Africa has used the process since 1955 and produces 150,000 b/d of liquid fuels from coal at Secunda. Sasol converts natural gas to synthetic fuels at Mossel Bay using proprietary Sasol techn o l o g y. For very large GTL plants, GTL c o m p e t e s directly with LNG and will therefore have to have a cost advantage with respect to the latter. Capital cost figures for GTLvary from supplier to supplier. Shell has quoted a figure of $30,000 per daily barrel capacity (pdbc) for a 50,000 b/d unit. A 50,000 b/d plant using Exxon s A G C (Advanced Gas Conversion for the 21st Century) is said to cost in the neighborhood of $20,000 to $24,000 pdbc. Sasol is said to have reduced the capital cost by between 25% and 30% as a result of their slurry phase reactor development. Sasol quotes a figure of $30,000 pdbc for a 10,000 b/d unit, the lowest of the three companies. Sasol s figure was used in the study. Many of the announcements on cost reduction in G T L concern small plants. Syntroleum in

5 Energy Issues 5 Oklahoma, USA, has published a figure of $17,300 pdbc for a 5,700 b/d unit, considerably lower than any of the above figures. Recently Syntroleum, Texaco and Brown & Root announced a plan to construct a 2,500 b/d floating production GTLplant. Hindsford of Australia and Rentech of Colorado, USA are both said to be focusing on plants smaller than 5,000 b/d. British Petroleum has recently announced a new proprietary GTL process. Although there is limited data in the literature, the target plant capacity appears to be in the range 10-20,000 b/d. GTL plants are being considered in developing countries. Texaco is undertaking economic and technical feasibility studies to prepare for a GTL project near Manaus, Brazil, with a likely capacity of 20,000 b/d. Chevron is pursuing the construction of a 20,000 b/d GTL facility at Escravos in Nigeria, where the Chevron-NNPC Escravos Gas Project is now producing sales gas from offshore oilfields Viability of the Technologies for Small Gas Fields The gas values of the ten most promising processes, as well as those of GTL and a combined ammonia/urea complex, are shown below. A localization factor of 1.3 was selected for the table. Where the gas value is higher than the supply cost, the process is potentially commercially viable. Supply costs are not shown in the table because they are specific to each gas field. As a first approximation of viability, however, a process may be considered economic if the gas value exceeds $0.50 per million British thermal units (MMBtu). If a country imposes a penalty for Table 3. Gas Values of Various Processes (Localization Factor 1.3 Relative to the U.S. Gulf Coast) Daily production Capital cost Product price Gas consumption Gas value Type of production in tons US$ million US$ in 25 years tcf US$/MMBtu Iron reduction (new) 2, /t Carbon black /t Dimethyl ether 4, /t Iron reduction (Mildrex) 2, /t Dimethyl ether (DME) 1, /t Methanol (land-based) 2, /t Methanol (floating production) 1, /t Gas-to-olefins (GTO) 2,400 ethylene 1, /t ethylene Ammonia` 1, /t Methanol 1, /t Gas-to-liquids (GTL) 20,000 b/d /bbl Ammonia/urea 3, /t urea Note: t = metric tons; bbl = barrel.

6 6 Commercialization of Marginal Gas Fields flaring gas, the supply cost of gas may even be negative, making many of the processes listed below potentially attractive. The use of natural gas for direct reduction ( D R ) of iron oxides for subsequent use in the manufacture of steel gives the highest gas value for gas fields in the range upwards of 0.25 tcf. New processes that can handle iron ore fines rather than pelletized or lumpy ores are particularly attractive economically. The final economics of this method will depend on the distance between the iron ore deposit and the gas field, the purity of the ore (iron content; the amount of metallic residuals, such as copper, nickel, and cobalt; and the amount of mineral oxides, such as silica, magnesia, alumina, and titania), the distance of the DR or steel plant from a harbor and, for steel manufacturers, the availability of low-cost electricity. For very small gas fields, producing about 0.1 tcf, a novel process for manufacturing carbon black and hydrogen from natural gas gives a high gas value. The carbon black plant needs to be located close to a hydrogen consumer, such as a refinery or a DR plant. The economics of methanol plants for gas fields that produce 0.5 to 1.0 tcf are attractive. The concept of a floating production methanol plant represents a novel technology which has several advantages. It is interesting to observe that construction of a methanol plant with a daily capacity of 2,500 tons using gas was recently announced for the Alba field off Equatorial Guinea (0.85 tcf). The field reserves are sufficient to cover more than 25 years of methanol production. The simplified economic analysis carried out in this study estimates a gas value of $1.4/MMBtu even after adding 30 percent to the announced capital cost of $300 million for the project. Although the conversion of natural gas to d i m e t h y l ether (DME) is economic on paper, as shown in Table 3, DME is not likely to emerge as a clean substitute for diesel in most developing countries for the foreseeable future. DME is a gas at ambient temperature and pressure and would require a new storage and distribution infrastructure. Gas-to-olefins (GTO) and methanol-to-olefins (MTO) call for enormous economies of scale and are not suitable for fields in the range of 0.25 to 2.0 tcf. A stand-alone ammonia plant is not likely to be commercially viable for marginal gas fields because ammonia must be stored and transported under pressure. An alternative is to build a urea plant adjacent to the ammonia plant. The combined economics, however, remain poor. Gas-to-liquids (GTL), conversion of natural gas to synthetic fuels (synfuels), is an emerging area of technology. At present, it appears that only l a rge synfuel plants (20,000 50,000 b/d), consuming 2 tcf or more of natural gas in a 25-year period, are commercially viable because of the considerable economies of scale required. Based on SASOL s figure of $30,000 pdbc for a 10,000 b/d unit and an overall product price of $22 per barrel, a 20,000 b/d unit is not economic. Raising the product price by 15% to $25 per barrel increases the gas price to $0.55.MMBTU. Significant development work is under way to make smaller plants (for example, those producing 5,000 b/d) economic. If and when the viability of small plants is commercially demonstrated, G T L technology may be seriously considered for m a rginal gas fields. Such a development would represent a major breakthrough for gas utilization, and would significantly increase the total amount of economically recoverable oil and gas reserves

7 Energy Issues 7 worldwide. Given the level of interest in GTL a n d of development work undertaken at present, it may not be long before a breakthrough occurs. With novel synthesis gas processes, more selective catalyst systems, and reductions in capital costs, the first profitable 5,000 b/d synfuel plant requiring only about 0.4 tcf of gas in 25 years of operation could be contracted within the next few years. Conclusion The gas values given above are not meant as definitive assessments of a specific process as applied to a particular gas field. The economics have to be calculated on a case-by-case basis, but the table does provide a first order assessment. Marginal fields around the world could be subjected to examination under the broad criteria used in this study for size, location, proximity to market, and gas value as a way of getting a good first approximation of their commercial potential. Energy Sector Management Assistance Programme (ESMAP) The paper was prepared using the analysis carried out in the ongoing ESMAP project Commercialization of Marginal Gas Fields in Africa. 1 The Energy Sector Management Assistance Programme (ESMAP) is a global technical assistance program jointly sponsored by the UNDP and the World Bank. ESMAP provides policy advice on sustainable energy development to governments of developing countries and of economies in transition. ESMAP centers its interventions around three priority areas: energy sector reform and restructuring increasing access to modern energy for unserved or underserved populations promoting environmentally sustainable energy practices. ESMAP s activities are executed by energy staff in the World Bank under the guidance of the ESMAP Manager. 1. Commercialization of Marginal Gas Fields, ESMAP Report 201/97, The World Bank (1997).

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