From crude oil and natural gas to the C1-C4 building blocks: The economics: feedstock, scale, integration and carbon

5.1 Feedstock price decides who sits at the bottom of the cost curve

A cost curve ranks plants from cheapest to dearest. The cheapest producers keep running when prices fall, and the dearest set the price when supply is tight. For high-value chemicals, the IEA (2018) concludes that feedstock is the most influential factor in regional advantage. Depending on the route, feedstock is 15-85% of the levelised cost of HVCs. Levelised cost spreads the plant's capital over its life and adds running costs. Crude oil sells at a similar price worldwide, but natural gas prices can differ by a factor of four. Ethane and LPG are either unavailable in some regions or must be shipped at extra cost.

That explains the map. In both 2010 and 2017, Middle East ethane crackers were the cheapest route to a tonne of HVC. Wittcoff explains why. Saudi ethane comes from gas produced alongside oil, which would otherwise be flared. It was priced at about $38 a tonne, the cost of separating and transporting it. The US shale boom then narrowed the gap. Between 2010 and 2017 the cost difference between Middle East and US ethane cracking shrank more than threefold. US ethane prices fell by about two-thirds, and in some years ethane was left in the gas stream ("ethane rejection").

Regional feed mixes follow. US HVC feed is 55% ethane, 34% LPG and under 10% naphtha. The Middle East uses ethane and LPG for over half its feed and exports more than 90% of its naphtha. China relies on naphtha for over 90% of its HVCs. Europe used naphtha for close to 75%. But the curve is not only about feed price. When propylene is scarce, naphtha's co-product credits can make it competitive, as the earlier worked example showed.

• IEA (2018), Ch 2 and Box 4.2 · pdf pp. 31-34, 37, 42, 76
• Wittcoff (2004), Ch 2 section 2.2.1.2 · pdf pp. 97-102

5.2 Capital, scale and integration: why crackers are huge and sit next to refineries

Capital is the second cost layer, and it depends on the feed. Wittcoff ranks cracker capital cost from low to high: ethane, ethane-propane, light naphtha, full-range naphtha, then gas oil. Heavier feeds make more co-products, so they need a larger furnace section and more separation columns per tonne of ethylene. Flexible crackers that can switch feeds cost more again but carry less risk. The IEA's 2018 cost assumptions put capital at $1,500 per tonne of annual HVC capacity for an ethane cracker, $2,050 for a naphtha cracker and $1,000 for an MTO unit. Fixed operating costs add 2.5-5% of capital a year.

Scale is the third layer. Wittcoff cites the square-cube law: a vessel's capacity grows with its volume but its cost with its surface area. So the cost of a whole petrochemical plant rises only with about the 0.6 power of capacity. Labour is a small share, around 2% of steam cracker cash cost. Typical cracker size grew from 70 million lb a year in 1951 to 1 billion lb in 1972. By 2001 BASF/Fina's Port Arthur cracker made 2 billion lb (about 0.9 Mt). Brennan (2020) records a 1.5 Mt a year US ethane cracker commissioned in 2017.

Integration is the fourth layer. The IEA (2018) explains that a refinery and cracker on one site share utilities, logistics and overheads. Each also uses the other's by-products. Low-value naphtha feeds the cracker. Cracker hydrogen feeds the refinery's desulphurisers, and pyrolysis gasoline can go back to the gasoline pool. China is the most integrated: over three-quarters of its HVC capacity sits beside refineries. About 40% of European naphtha cracking capacity is integrated, and under 20% in the US. In the US and Middle East, cheap gas liquids go straight to crackers instead.

• Wittcoff (2004), Ch 1 section 1.3.4 and Ch 2 section 2.2.1.2 · pdf pp. 58-59, 98
• IEA (2018), Ch 2 · pdf pp. 33, 38-40, 42
• Brennan (2020), Ch 2 Case C and Ch 4 · pdf pp. 55-56, 125

5.3 Energy and emissions: where the carbon goes for each building block

The chemical sector is the largest industrial energy user, the IEA (2018) reports. It takes about 10% of world final energy and 14% of oil and 8% of gas demand. Yet it ranks only third among industrial CO₂ emitters. Much of its energy input is feedstock carbon that ends up locked in products rather than burned. Primary chemicals account for about 60% of the sector's CO₂. Ammonia contributes 49% of that, HVCs 27% and methanol 24%.

The IEA's average direct emissions per tonne in 2017 were about 2.4 t CO₂ for ammonia, 2.3 t for methanol and 1.0 t for HVCs. The reasons differ. A steam cracker burns its own methane and hydrogen off-gas as fuel and exports steam. Its carbon cost is mostly the furnace. Ammonia removes all the carbon from methane, because only the hydrogen is wanted, so the CO₂ leaves as a concentrated process stream. That stream is cheap to capture, as little as $25 a tonne. Nearly half of ammonia's process CO₂, about 130 Mt a year, is already used to make urea. But the carbon returns to the air when the urea is spread on fields.

Feedstock type dominates both energy and emissions. Coal-based ammonia emits more than two and a half times as much CO₂ as gas-based ammonia, and coal-based methanol almost five times as much. Within gas and liquid feeds the differences are small. The best naphtha and best ethane crackers are within 5% of each other on process energy. Local factors matter more: an average Asian naphtha cracker is about 10% above best practice, but some regions run up to 50% above. In feedstock terms, the IEA puts HVCs at about 72 GJ per tonne and ammonia and methanol at nearly 20 GJ per tonne.

• IEA (2018), Ch 2, Ch 3 and Ch 4 · pdf pp. 27, 29-30, 46-47, 50-51, 84-86

See it in the table

Check your understanding

According to the IEA, what is the single most influential factor in regional cost advantage for HVCs?

Why does a naphtha cracker cost more to build per tonne of ethylene than an ethane cracker?

Ammonia's process CO2 is cheap to capture compared with combustion CO2. Why?