Oil and Energy Trends, 17 October 2003

Contents

• Focus: Liquids from gas: technological fix or expensive mistake?
• Gas and Power: Gas prices provide key to petrochemical future
• Looking Ahead: Oil markets seek new pricing mechanisms

Focus: Liquids from gas: technological fix or expensive mistake?

• Miracle technology?
• GTL Projects
• Raising the stakes
• Qatar and Iran
• Finding a way forward

Oil companies in search of clean fuels and gas companies looking for markets for economically marginal gas fields are pinning many hopes on gas-to-liquids (GTL) technology.  The oil industry values the ultra-low-sulphur gasoline and high cetane diesel that GTL plants produce, while gas producers see GTL as a way of selling gas from small and remote fields that avoids the building of costly pipelines to carry low volumes of gas.  Large numbers of GTL plants are being proposed in many countries.  Several commentators see them as transforming the hydrocarbon business over the next few years.  Is GTL the breakthrough its supporters claim or is the technology perhaps being oversold?

Back to Top

Miracle technology?

The GTL process takes the methane gas molecule and transforms it into more valuable and more easily transportable liquids: hence its attraction for gas companies with small, marginal fields.  Such gas deposits are often described as ‘stranded gas’ because they are normally uneconomic to develop.  The GTL process essentially increases the proportion of carbon to hydrogen in the gas so as to produce the heavier liquids.  It is based on a process dating back to the 1920s, known as ‘Fischer-Tropsch’, which was used by Germany in the 1940s to produce liquid fuels from coal.

The GTL process firsts reacts the methane with oxygen to produce a synthesis gas of carbon monoxide and hydrogen.  A further process removes the surplus hydrogen as water while the remaining carbon and hydrogen is converted into long-chain hydrocarbon molecules (liquids).  The production of these hydrocarbon liquid chains involves passing the synthetic gas over a catalyst.  It is this catalyst that is the key to the process of transforming methane gas into liquids.  Such catalysts have only been commercially developed over the last ten years or so: hence GTL’s fairly short history.  The hydrocarbon chains produced by the catalyst process are further processed, for example by hydrocracking, in order to balance the ratio of hydrogen to carbon properly and to determine the precise nature of the liquid yield.  The liquids produced are mainly naphtha, kerosine and gasoil, and their proportions can be varied according to the final processing.

The result of all this is high quality liquids that can be further processed (naphtha) or blended (kerosine and diesel) to make clean, high performance fuels.  Such fuels are in increasing demand because of the trend in most major oil markets to lower limits for sulphur, aromatics and other pollutants (see ‘Looking Ahead’, May 2003).  In the EU, for example, the sulphur content of gasoline and diesel is to be reduced to 50 parts per million (ppm) from 2005, reducing to 10 ppm in 2009.  Japan will go down to 10 ppm in 2008, while the USA will adopt a 30 ppm limit for gasoline in 2005 and a 15 ppm ceiling for diesel a year later (see Table A).  To reach such limits, refiners generally have to distil out the heavier fractions containing the highest concentrations of sulphur, thus reducing their yields of gasoline and diesel, or invest in expensive hydro-treating to remove the sulphur from the lighter products.  Another solution is to gasify crude oil to produce synthesis gas (removing sulphur and other pollutants at this stage) then use the Fischer-Tropsch process to turn the gas into liquids.  Yet another solution is to start with gas instead of crude oil and produce liquids via the GTL process.

GTL seems ideal for such a product slate.  It also meets new cetane standards for diesel.  GTL diesel cetane is, in fact, far higher than is required at present.  Diesel produced by this method has a cetane number around 70, compared with, say, the 51 minimum required in the EU.  High cetane means better combustion properties and reduced exhaust emissions.  The aromatics content is also low, aromatics being another source of air pollution.  GTL can also produce high quality kerosine and petrochemical naphtha.  Much of the output from commercial plants, however, is likely to be diesel.  A typical product yield from such a plant would be 70% diesel; 25% naphtha; 5% other products, which could include solvents and waxes.

Back to Top

GTL Projects

Over 2mn bpd of GTL capacity has been proposed in more than a dozen countries (see Table B).  In many cases, the plants are quite small (under 50,000 bpd) and have been planned in association with the exploitation of stranded gas reserves.  Recently, however, a new generation of projects has begun to emerge: plants of 100,000 bpd and over are being proposed including one of 300,000 bpd in Qatar for commissioning in 2016.  These new, world-scale plants are associated with much larger gas deposits than the first generation plants.  Not all the plants are firm proposals, and some have still to specify such fundamentals as size and planned opening date.  There seem, however, to be reasonably firm proposals for about 1mn bpd of GTL capacity by the end of the decade.

Stranded gas schemes include projects in Africa and Latin America.  Bolivia is seen as almost the ideal country for GTL with its combination of small gas fields and high imports of diesel, added to which is a desire to reduce sulphur levels in transport fuels.  Three plants are currently under consideration, using GTL technologies developed by US firms Rentech and Syntroleum.  The Rentech proposal is for a 10,000bpd plant to be built jointly with GTL Bolivia, with a possible increase to 50,000 bpd.  Spain’s Repsol YPF has proposed two other plants: one of 13,500 bpd and another of 90,000 bpd, which might even be an export-oriented facility.  The two Repsol YPF plants would use Syntroleum’s technology: all three would use Bolivian gas from fields in the Santa Cruz area.  GTL plants might also provide an alternative gas buyer to Brazil, which has been trying to reduce the volume of gas it buys from Bolivia following a fall in gas demand there (see ‘Gas and Power’, June 2003).  Several issues, however, remain to be resolved before any of the Bolivian GTL schemes can go ahead, including the all-important one over the transfer price of the gas into the plants.

Chile, Brazil, Peru, and Ethiopia are among several other countries planning GTL plants to serve small gas fields.  These schemes tend to be for plants in the range of 10,000–20,000 bpd.  Several small plants are also being developed in the USA, though these are often facilities designed to demonstrate new GTL technologies.  Trinidad is looking at the idea of building a 10,000bpd plant as the possible first stage of a GTL export industry to stand alongside its export-oriented liquefied natural gas (LNG) and petrochemical industries.

Back to Top

Raising the stakes

The most recent proposals tend to be for much larger plants than those described above.  In several cases, the proposals are for plants to operate alongside well-established gas marketing and processing operations.  These include plants in Nigeria, Australia and, above all, in Qatar and Iran.

The Nigerian proposal is for a 34,000bpd plant on the Escravos field, to be developed by ChevronTexaco and South Africa’s Sasol, which is one of the principal companies developing GTL technologies.  The aim of the Escravos project appears to be to monetize some 400 mn cfd of gas that is currently flared.  Nigeria is trying to reduce flaring drastically by imposing heavy financial penalties on companies that do flare gas.  The aim of the scheme is to export the naphtha and middle distillate produced by the plant.  The project also includes some recovery of natural gas liquids (NGL) from the gas separately from the GTL unit, which would boost the output of light products further.

Sasol and ChevronTexaco are also planning a GTL scheme in Australia.  The proposal is for a 50,000bpd unit alongside a proposed LNG export terminal on Barrow Island, off north-west Australia.  Both facilities would use gas from the Gorgon field.  Development is dependent on a number of factors, including favourable taxation and regulatory policies.  These have been a sticking-point for a number of gas developments down under (see ‘Focus’, November 2002).

In the Australian case, GTL appears to be a response to an excess of natural gas following a series of large discoveries.  The Gorgon development, for example, has reserves estimated at over 40 trillion cubic feet (tcf): substantially more than the North West Shelf project, off Western Australia.  There are other large gas projects in neighbouring countries that are also aimed at the Australian market, in Papua New Guinea and East Timor.  In addition to these, there is the prospect of growing competition from coal-bed methane (see ‘Looking Ahead’, June 2003).  This year, gas produced from coal seams will account for 30% of all the gas consumed in the state of Queensland.  Coal provides still further competition for gas producers in the power generation sector: normally the sector that does most to drive the demand for natural gas.  Many of the power stations that burn gas are small and medium-sized peaking plants, which only operate intermittently.  All this has helped to keep the bulk fuel-burning market competitive and gas prices down, making the market for clean oil products, such as low-sulphur diesel (see Table A) attractive to promoters of GTL schemes.

Back to Top

Qatar and Iran

The country heading the list of GTL projects is Qatar, with plans for up to 674,000 bpd of capacity (see Table C).  The aim of the GTL programme is to find new markets for Qatar’s 509 tcf of gas: the third-largest proven reserves in the world after Russia and Iran.  Qatar is the Middle East’s largest exporter of gas and also has a substantial industrial sector based on gas and gas liquids (see Table D) to which GTL is soon to be added.

So far, however, only one of Qatar’s proposed GTL plants is under construction: the remaining four are still being studied.  Even the final size of the projects has yet to be determined.  The one that is going ahead is the 34,000bpd venture between the government-owned Qatar Petroleum (QP {http://www.qp.com.qa/qp.nsf}) and Sasol.  Earlier this year, the two companies awarded the engineering, procurement and construction contract to France’s Technip-Coflexip.  The contract is worth $675 mn and construction is expected to be completed in late 2005.  The scheme uses a Sasol process known as Sasol Slurry Phase Distillate and will produce 24,000 bpd of gasoil, 9,000 bpd of naphtha, and 1,000 bpd of liquefied petroleum gas (LPG).  The entire project, known as Oryx GTL, is expected to cost $900 mn.  Ownership of the plant is split 51:49 in favour of QP and the unit is to be sited in the industrial zone of Ras Laffan.  There is provision for further production trains of 20,000 bpd each.

Iran also has an impressive list of projects (see Table E) but some of these appear to have run into problems.  The aim of the Iranian programme is to use gas from the South Pars field, which is estimated by the National Iranian Oil Company (NIOC {http://www.nioc.org/}) to contain up to 300 tcf of recoverable reserves (see ‘Gas and Power’, January 2003).  Negotiations to develop the field are not proceeding smoothly, however, and several international oil and gas companies have complained that rates of return are unattractive.  At least one large GTL project is in jeopardy.  The Iranians want to use their GTL plants to manufacture both refined products and petrochemical feedstocks.  They hope to export some of the output.

Back to Top

Finding a way forward

A considerable aura of uncertainty surrounds the GTL projects outlined above.  Although the basic technology is about 80 years old, its application to methane is more recent and the commerciality of most systems remains unproven.  The few plants that exist at present are mainly small pilot plants, with just two commercial-size units in operation: Shell’s Middle Distillate Synthesis (SMDS) plant in Bintulu, Malaysia and a plant operated by Mossgas in South Africa, neither of which is anywhere near the size of some of the facilities planned in Qatar, Iran, and elsewhere.  The Bintulu plant produces 12,500 bpd of liquids, though capacity is to be increased by a further 2,500 bpd by debottlenecking.  The Mossgas plant is about 40,000 bpd.  Both plants have had a somewhat chequered history.  The SMDS plant was badly damaged by an explosion in 1997 and did not reopen until 2000, though it appears that the incident was caused by forest fires in Malaysia and not by any technical failure at the plant.

The Mossgas plant was intended to produce liquids from a small gas field in Mossel Bay.  Its development dates from the apartheid era and was part of a general policy of producing liquid fuels from domestic resources at a time when South Africa was subject to international trade sanctions.  (Sasol’s liquids-from-coal industry was set up earlier in similar circumstances.  More recently, it has been adapting its Fischer-Tropsch process to run on gas).  While Mossgas had some technical successes in its GTL process, the plant is widely reckoned to have been a financial failure.  One South African oil industry executive went so far in 1997 to describe Mossgas as ‘an unmitigated disaster’.

Improvements in technology and catalysts since then have undoubtedly improved the economics of GTL, but there is still no conclusive proof that GTL can work on a large industrial scale.  In many cases, plant economics appears to be based on the supply of gas at below-market prices.  One major disadvantage of the GTL process is that around one-third of the calorific value of the gas is lost in transforming the methane into liquids.  GTL’s supporters, on the other hand, may point to the increasing cost of removing sulphur and other pollutants to meet the low limits mandated for most markets in the industrialized countries (see Table A).  Similar emission levels are possible with compressed natural gas (CNG), but GTL has the advantage of producing liquids that can be distributed through the existing oil industry, unlike CNG, which needs a distribution and retailing network setting up from scratch.  What is really needed to settle the matter is a fully commercial, world-scale GTL plant, and this still looks several years away.

Back to Top

Gas and Power: Gas prices provide key to petrochemical future

Rising gas prices could be undermining the economics of several major gas-using industries.  Electricity generation has become considerably more expensive in many parts of Europe and North America (see ‘Focus’ September 2003).  It is not only electricity producers who are suffering, however.  The petrochemical industry is also badly affected by rising gas prices in several areas, especially in the USA.

Petchems under threat

The US petrochemical industry uses a high proportion of gas in its feedstock slate.  In Europe and many parts of Asia, there is a much higher use of oil-based feedstocks, such as naphtha.  The American petrochemical industry has preferred gas-based feedstocks more or less since its inception, since gas has traditionally been cheaply available compared to crude oil. 

Petrochemical producers are interested mainly in the liquids found in the gas.  The dry gas, methane, is generally not used, other than for methanol and a few other petrochemicals.  The heaviest of the gas liquids, propane, butane and condensate, are usually fractionated and recovered as liquids: propane and butane as liquefied petroleum gas (LPG) and condensate as a separate stream that is often added to heavier crude oils to lighten them.  LPG and condensate traditionally command a high price, especially LPG, which is a versatile fuel as well as a valuable refining and petrochemical feedstock.  This leaves ethane, the lightest of the gas liquids.  Ethane requires lower temperatures and higher pressures to extract it from methane than do the heavier liquids.  Moreover its fuel use is limited, which tends to confine it to the petrochemical market.

Since about 1999, however, US demand for methane has begun to grow strongly, driven to a considerable extent by demand from new gas-fired power stations across the USA.  This has pushed up the price of methane which, to some extent, has dragged the price of ethane along in its wake, bringing to an end nearly two decades of low gas prices.  With gas demand still growing and domestic supplies falling, US gas feedstock prices look set to remain high for several years.

Growing competition

High prices for methane since 1999 have been accompanied by the shut-down of over 40% of US methanol production capacity.  Some producers fear a similar process is about to start with ethane and its associated petrochemical production.  Ethane is used to produce ethylene, one of the primary building-blocks for the petrochemical industry.  Plentiful and cheap supplies of natural gas in the 1980s and 1990s made ethane the feedstock of choice for ethylene crackers built in the USA in this period.

US gas prices are not only increasing in absolute terms but are also rising relative to those of oil.  This presents US operators of gas crackers with a double problem: it makes them less competitive compared with crackers run on liquids such as naphtha, and, more significantly, less competitive against crackers run on lower-priced ethane: those of the Middle East.  US gas prices have recently been around $5/mn Btu, compared with $0.75–$1.25 in many parts of the Middle East.  Furthermore, Middle Eastern producers generally do not have to worry about abrupt changes in feedstock prices since these are set at fixed prices over a number of years.  In Saudi Arabia, the price of ethane was fixed by the government at $0.50 per mn Btu from the 1970s to 1998, when it was raised to $0.75 per mn Btu, at which level it remains.  Iran is offering ethane to some petrochemical joint-ventures at a price of $1.25 per mn Btu, fixed for ten years.

Unsurprisingly, perhaps, half of all the world’s new ethylene capacity planned for the period 2003 to 2010 is located in the Middle East, which is set to double its capacity between now and the end of the decade.  The region has attracted most of the world’s main petrochemical producers, including BASF, BP Chemicals, ConocoPhillips, Dow Chemical, ExxonMobil and Shell.  These and others are involved in a series of ventures with state-owned companies, such as Saudi Basic Industries Corporation (Sabic), Iran’s National Petrochemical Company (NPC), and Qatar Petroleum (QP).

Targeting Asia

One of the factors driving the expansion of Saudi Arabia’s petrochemical industry is the decision to increase gas production substantially through a series of partnerships with major international oil companies.  The Saudis recently signed an exploration agreement with Shell and Total covering 77,000 square miles in the Rub al-Khali.  Three more blocks varying in size from 11,500 to 20,000 square miles are due to be offered in January 2004.  The Saudi oil ministry has said that a substantial proportion of the gas from these new developments will be allocated to the petrochemical industry.

Iran also has ambitious plans to use its ethane production to supply a series of new crackers.  Ethylene production is slated to rise to 8.7 mn tonnes pa by 2010, compared with only 0.7 mn tonnes pa at the start of the decade.  NPC aims to have 5% of the world petrochemical market by 2010 and has further plans for petrochemical production based on synthesizing methane into liquids (see ‘Focus’).  Qatar is also increasing its cracking capacity.  Following the commissioning of a 0.5 mn tonnes pa ethylene unit late last year, QP is to build a further cracker of up to 1.6 mn tonnes pa at Ras Laffan, in conjunction with Atofina.

A substantial proportion of the output of these new crackers and associated downstream units is aimed at the Asian market, and particularly that of China.  China is now the world’s largest importer of bulk petrochemicals, such as ethylene, which it turns into plastics, textile fabrics, and other consumer products for export.  Middle Eastern suppliers are gaining an increasing share of China’s import trade and Sabic even hopes to have a plant of its own there.  All China’s suppliers are hoping the boom lasts and that Peking is not obliged to rein-in its exports in response to complaints from the Americans and others that China is threatening their own downstream petrochemical industries by selling its plastics and other products at unfair prices.

Back to Top

Looking Ahead: Oil markets seek new pricing mechanisms

Discontent about crude-oil reference prices is becoming widespread across world oil markets.  Brent-Forties-Oseberg (BFO), which replaced the 15-day Brent market in 2002, is under attack from many quarters over the way it is assessed by the main price-reporting service.  In the USA, there are claims that the market in West Texas Intermediate (WTI) crude can be too easily manipulated by large traders, while the Middle East continues to search in vain for a benchmark crude to replace Dubai.

Reporting BFO

The UK’s Brent crude has acted as the reference crude for more than half the world’s oil production.  The method of pricing has had to be modified, however, owing to a decline in Brent production from over 1 mn bpd in the 1980s to around 230,000 bpd this year.  Adding Forties and Oseberg to the price assessment for Brent added a further 1.1 mn bpd of North Sea production, of which 780,000 bpd is Forties.  The method used by Platt’s price reporting service to assess BFO prices, however, has attracted some criticism.

Platt’s assesses the price for dated, or prompt, BFO between 5.00 and 5.30 pm each working day.  Several oil market players have protested that this is too short a period on which to base a daily price assessment, and that the price is open to manipulation by companies trading heavily in that 30-minute period.  The use of BFO to replace Brent appears, on the other hand, to have met with near-universal approval, even if some of the issues on price reporting still need to be resolved.

US pricing

A different pricing issue has arisen in the USA over the pricing of WTI.  Here, the problem is one of logistics.  WTI is a domestically-produced pipeline crude.  Whereas North Sea crudes are priced at marine loading terminals, such as Sullom Voe in the Shetland Islands, WTI is priced at various points along the US pipeline system.  The point chosen to be representative of the entire WTI market is Cushing, Oklahoma, which is the delivery point for futures contracts traded on the New York Mercantile Exchange (Nymex).  The problem at Cushing is that the storage terminals are primarily owned by just four companies: BP, Plains, Shell, and Teppco.  WTI prices are sensitive to movements in and out of storage and one company, BP, has been accused of using its dominant position in Cushing storage to manipulate the price of WTI.

Some traders want another reference crude to act as a check on WTI prices.  The most likely candidate is one of the crudes produced in the Gulf of Mexico.  These are also pipeline crudes, but they tend to be priced at points along the Gulf Coast and, as such, are generally more representative of internationally-traded crudes.  WTI is particularly prone to price movements based on conditions in the Texas and Mid-Continent markets.  Supporters of other crudes point out that the inland US market is becoming less important as the proportion of imports in the US oil balance increases.  US oil production is about 8 mn bpd: crude oil imports this year are averaging over 9 mn bpd.

Oil production in the US Gulf is, in any case, greater than that from the fields that supply Cushing.  Gulf output this year is likely to exceed 1.7 mn bpd, compared with 1.4 mn bpd for the mainly Texan fields that feed into Cushing.  Gulf crude production, moreover, is rising, while that of Texas is in decline.

One widely-touted candidate for the role of Gulf reference crude is Mars, which is delivered to a pipeline terminal at Clovelly, Louisiana, on the Gulf Coast.  Louisiana is the principal point of entry for US imports of crude oil and possesses the USA’s largest deepwater crude terminal.  Trading in Mars is not well-developed enough to prompt a wholesale switch away from WTI.  Mars is, in any case, a different type of crude from WTI, being heavier and higher in sulphur.  Nevertheless Louisiana eventually looks like mounting a serious challenge to Texas and Oklahoma as the reference point for US crude oil pricing.

The other Gulf

Oil price benchmarks are under scrutiny in the Persian Gulf as well.  Falling production in Dubai makes that crude increasingly unsuitable as a marker grade (see ‘Looking Ahead’, January 2003).  Oman is increasingly being used to supplement price assessments of Dubai, owing to its similarity to Dubai and much higher production.  Oman, though, is itself priced in relation to Dubai, which has prompted oil traders to seek a third crude to use as a reference.

One possibility is Basrah Light.  It, too, is similar to Dubai and its production should exceed that of Dubai and Oman combined once some kind of order returns to Iraq.  Its future as a reference crude, however, depends on Iraq’s willingness to allow it to trade freely.  The Iraqis may well decide to follow the practice common in other Middle Eastern countries of restricting spot sales, leaving the Middle East without a suitable, independent price marker of its own.

Back to Top

© Blackwell Publishing Ltd, 2003