Although gas production increased by more than 70% between 2003 and 2013 according to BP figures, harnessing its potential presents a number of challenges. Saudi Arabia has no plans to export gas, seeing it as feedstock for local power, desalination and petrochemical plants in order to free up more oil for export.
Saudi Aramco’s 2013 annual report, published in April 2014, revealed that its raw gas output for such plants was 4.02trn standard cu feet, the most in a single year in the company’s history. The firm also produced 455.9m barrels of natural gas liquids (NGLs), including 86.8m barrels of condensate. The report said Saudi Aramco’s gas plants were capable of processing 13.2bn standard cu feet per day (scfd). After the company’s executive committee meeting in March 2015, its then-CEO and president, Khalid Al Falih, said Saudi Aramco had produced a record volume of gas in 2014, and discovered eight new oil and gas fields.
According to the US Energy Information Administration (EIA), 70% of Saudi Arabia’s gas output was associated with the Ghawar, Safaniya and Zuluf oilfields as recently as 2011 and 60% came from Ghawar alone. However, the EIA suggests that significant additional boosts in production are likely to come from other parts of the country. In 2012 production began from Karan, the Kingdom’s first non-associated gas field. It has a capacity of 1.8bn scfd, which is fed by a 110-km sub-sea pipeline to the Khursaniyah gas plant and subsequently used for industrial feedstock, water desalination and electricity generation.
In spring 2015, the Wasit gas processing facility was due to come on-stream north of Jubail. It has been built to handle the combined 2.66bn scfd output of two other non-associated fields in the Gulf, Hasbah and Arabiyah, which are expected to produce 1.3bn scfd and 1.2bn scfd of Khuff gas, respectively. There have been local media reports that the high sulphur content of the gas from these fields has caused some delays in the Wasit facility coming on-line. However, Saudi Aramco says that when the plant is fully operational it will be able to supply 1.75bn scfd to customers through the Master Gas System and could potentially handle peak summer or emergency demand of 3.05bn scfd.
According to Saudi Aramco’s 2013 annual report, the Karan and Wasit developments will raise the Kingdom’s gas processing capacity by about 40%. The Wasit plant’s fractionation (separation process) module is designed to produce ethane, propane, butane and natural gas. The cogeneration power plant at Wasit will produce 750 MW of power and 4200 tonnes of molten sulphur a day. The plant will be the first in the Kingdom to use Shell’s Sulfinol-M gas treatment technology, raising the efficiency of sulphur recovery from 95% to 99.1%.
Another key component of Saudi Aramco’s non-associated gas development programme is taking place on Saudi Arabia’s Red Sea coast in the Tabuk region. The Midyan field, though discovered in the 1990s, only began to be developed in 2013. When fully operational in 2016, Midyan will be capable of producing 75m scfd of non-associated gas and 4500 bpd of condensate. Two 98-km pipelines will feed these products to a power plant near Duba for electricity generation. Saudi Aramco’s non-associated gas programme is also designed to service a range of other industries, including the production of steel, cement, ammonia, antifreeze, solvents and fuels.
Associated Gas Improvements
The Saudi Aramco report also gives details of additional gas output from recent developments in its oilfields. It reports that the Khurais field is producing 320m scfd and that the new Manifa oilfield produces 90m scfd. The company has also boosted capacity at the Haradh gas plant by 8% following improvements to its sales gas compression relief system. This gives the plant the capacity to process an additional 150m scfd when necessary.
The company also reports significant improvements at its Shaybah oilfield, deep inside the Rub Al Khali. A new NGL recovery plant was scheduled for completion by the end of 2014 with production capacity of 270,000 bpd. The project involved building inlet facilities, gas treatment units, NGL recovery trains, residue and acid gas compression, NGL storage, and an upgrade of the gas-handling capacity of the four Shaybah gas-oil separation facilities. Power generation on the site was due to be increased to more than 1 GW with the installation of four cogeneration units, seven single-cycle units and a 50-km, 230-KV transmission line.
The Rub Al Khali is one of three areas Saudi Aramco is targeting in its drive to tap its reservoir of unconventional gas – deposits of natural gas trapped in tight sands and shale. The other two are South Ghawar and the country’s north-west. One of Saudi Aramco’s key goals is “large-scale expansion in exploration and development of unconventional resources”. In January 2015, former CEO and president Al Falih told a conference in Riyadh that the company had committed $7bn to this purpose and had already spent $3bn. He said Saudi Aramco would continue to invest $30bn-50bn a year on crude oil, gas and petrochemical development despite the fall in oil prices.
Although the $7bn being invested in developing shale is comparatively modest, the company is following the technological example set by the industry in the US. In its 2013 annual report the company said of shale, “the gas was not commercially viable to produce until recently” but that only two years after launching its own unconventional gas programme, it was ready to commit shale gas to a 1000-MW power plant for the Waad Al Shamal phosphate mining and manufacturing complex being built by a subsidiary of state-owned mining company Ma’aden. “Saudi Arabia will be among the first countries outside North America to use shale gas for domestic power generation,” the Saudi Aramco report said. In a statement to the Saudi Stock Exchange in July 2014 Ma’aden announced that the $7.5bn complex would begin production by 2016.
However, developing unconventional shale gas in Saudi Arabia faces significant challenges. Drilling tests indicated the Kingdom may have up to 600trn cu feet of shale gas, according to local media – twice as much as BP’s figure of 290.8trn cu feet for the country’s entire gas reserves. However, two of the three sites Saudi Aramco is exploring are in remote and dry desert areas. Fracking in the US relies on the ability to inject billions of gallons of fresh water into tight seams, but in Saudi Arabia groundwater is scarce. Even if seawater were used, it would have to be transported to the gas fracking fields from coastal areas. Another possibility, which has been explored in the US, is to use liquefied petroleum gas as a water substitute.
Another obstacle to such development is the domestic price structure for gas, which is highly subsidised and based on the cost of extracting associated gas. According to 2013 World Bank figures cited by the EIA, gas is sold to Saudi consumers for $0.75 per million British thermal units (Btu), well below the US ($3.75), the UK ($10.51) and Japan ($15.96). It would cost a minimum of $6 per million Btu to extract shale gas in Saudi Arabia, rising to $10 per million in some remote areas. The economics only make sense when the losses incurred in producing and selling unconventional gas are compared to the opportunity loss for Saudi Arabia every time it sells a barrel of crude to a state power station for $5 to generate electricity.
A barrel of crude oil contains 5.8m Btu of energy. At $10 per million Btu, the equivalent production cost of the most expensive equal volume of unconventional gas would be 10 x 5.8, or $58 a barrel. That $58 barrel would be sold to a Saudi customer for $4.35 at the $0. 75-per-million Btu rate, and so the producer would incur a loss of $53.65. If that same producer sold a barrel of crude to a Saudi power generator for $5, when it could have been exported for $60, then an opportunity cost of $55 is incurred. The upshot is that, even at an export price of $60 a barrel, the most uneconomical unconventional gas would still save the Saudi economy the difference between a loss of $55 and a loss of $53.65 a barrel, or $1.35 a barrel. Those losses are far greater when the export price of crude oil is above $60, and are higher still if the crude oil is being burned in power stations rather than turned into refined products with an even greater export value than the crude oil itself.