Just 10 years ago, many would have laughed at the thought that the United States (US) could soon become a net exporter of crude oil and petroleum products. But for one week in November 2018, for the first time in decades, it did just that. At the heart of this remarkable achievement is the country’s shale production. Crude oil production went from just over 4.7 mn barrels per day (mbpd) in October 2008 to 11.5 mbpd in Oct 2018, according to the US Energy Information Administration (EIA). In the same period of time, natural gas production grew by 35.8mn cubic feet per day.
If the US shale revolution has taught anything to the rest of the world, it is that research and development are essential to industry growth. US production did not boom overnight—advancements in technology allowed it to access previously inaccessible hydrocarbons, and introduced the US as one of the world’s leading oil producers. Technological breakthroughs came in three main areas: Directional drilling, hydraulic fracturing and increased computing power to set more precise drilling locations.
Oilfield services company Halliburton had a central role in the shale boom that revolutionised US production and marked a shift in the global energy landscape. It plans to replicate its success in North America in shale plays across Argentina, Canada, Mexico, China and Poland, among other countries. With a regional headquarters in the United Arab Emirates, Halliburton is within arm’s reach of the Middle East’s untapped unconventional resources—the Society of Petroleum Engineers estimates that the Middle East and North Africa (MENA) region holds 2,547tn cubic feet (tcf) of shale gas. North America, which has the most shale gas of any region, holds 3,840 tcf.
“The [national oil companies] of Saudi Arabia, Oman, Bahrain as well as Algeria and Kuwait are all looking into how they can develop their unconventionals,” says Ahmed Kenawi, Halliburton’s senior vice president of the Middle East and North Africa. “The unconventional resources in the Middle East are related to gas, so they will try to produce the gas to help feed into their local consumption, and then they can export more oil.”
This is not a far-fetched plan; Saudi Aramco started commercial production of unconventional gas from North Arabia field in May 2018, and supplied around 55 mcf per day of gas to a power plant in Wa’ad Al Shamal, a mining and industrial project in northern Saudi Arabia, the company announced in November 2018. It noted in a press release that its use of cutting edge technology for unconventional resources would cut costs by 70%.
In 2013, then Saudi Arabian Oil Minister Ali al-Naimi estimated that the nation had more than 600 tcf of unconventional gas. Oilfield services company Baker Hughes, a GE company, estimated the figure at 645 tcf. By comparison, Saudi Arabia has conventional gas reserves of 298.7 tcf. Khalid Al Abdulqader, Aramco’s general manager of unconventional resources, said in March 2018 that the Jafurah Basin, located near the world’s largest oil field, Ghawar, is similar in size to Eagle Ford shale in Texas, which is expected to produce 1.3 mbpd of oil and 5.5 mcf of gas per day in January 2019.
Saudi Aramco has made a bold push towards growing its conventional and unconventional gas portfolio—CEO Amin Nasser said that the company’s gas strategy would “attract investments of about $150bn over the next decade, with daily production reaching 23bn standard cubic feet a day from the current 14bn.” By 2040, he expects gas to make up 50% of the nation’s utilities mix.
“The commercialisation of unconventional gas production in the region, as pursued by ADNOC and Aramco, will allow these economies to progress towards self-sufficiency in gas, benefiting their petrochemical sector and lowering oil consumption for power generation through a transition to gas,” says Adnan Fazli, energy and resources leader at Deloitte Professional Services Limited.
According to the EIA, the US produced almost all of the natural gas it used in 2017. But gas is not only useful for internal consumption—as feedstock for the chemicals sector, it provides added benefit to Saudi Aramco, which is attempting to grow its downstream portfolio. Most notably, it plans to invest $100bn into the downstream sector in the next 10 years, excluding its planned acquisition of a 70% stake in Saudi chemicals giant Sabic. “We expect integration of upstream and downstream to be very important here [in the Middle East],” says Alan Gelder, vice present of refining and chemicals at Wood Mackenzie. “If you look globally, international oil companies have more refining capacity than crude capacity so they can argue in an energy transition they can migrate towards gas, there›s no risk of crude being stranded.”
Integrating across the value chain is an increasingly common strategy in the region, and oil and gas producers see the potential in leveraging their unconventional resources. In April 2018, Bahrain found approximately 20 tcf of gas offshore and 80bn barrels of shale oil. Like Saudi Arabia, Bahrain is working with Halliburton as its service provider, which drilled appraisal wells there in 2018. Oman’s Khazzan field, operated by BP, started production in September 2017 and is expected to recover 10.5 tcf of tight gas. ADNOC has signed multiple agreements for its unconventional gas resources, including giving a 40% share in the Ruwais Diyab Unconventional Gas Concession to oil major Total. Meanwhile, Saudi Arabia’s unconventional efforts are concentrated in the Northwest, South Ghawar, Jafurah Basin and Rub’ al-Khali. Saudi Aramco CEO Amin Nasser has set a target of 3 bcf of unconventional gas sales by 2030.
But the Middle East has its own set of challenges, and the cost of producing a barrel of oil equivalent could be higher in the region than it is in North America—total capital costs per well in five major onshore US plays ranged from $4.9mn to $8.3mn in 2014, according to the EIA. “The NOCs are hungry to find out how we can lower the cost exactly like the US,” Kenawi says. Shale production in the US has an approximate breakeven price of about $50 per barrel of West Texas Intermediate (the US benchmark).
“The key is moving all the experience and learning curve of North America into the Middle East as fast as possible,” Kenawi says. “What we are trying to do is to take one more step and figure out how to localise it.” Localisation is a regional buzzword, but it has tangible benefits to oil and gas producers. Kenawi emphasises that the technology needed to extract unconventionals exists in the Middle East, but Halliburton is working to localise it in order to bring costs down. “We are bringing the learning curve of North America in reservoir insight, customised chemistry and surface efficiency into the Middle East and we are trying to make everything locally here, because the real success in the US is everything is happening locally,” he adds.
One obvious difference between the two regions, often cited by sceptics, is the availability of fresh water. Fracking requires up to 9.6mn gallons of fresh water per well, according to a 2015 study of US plays by US Geological Survey. “We have started working on how we can use not only fresh water, but saline water for fracking,” he says. “We have performed two trials but not yet on a large scale—we’re still working on those technologies.” He say the trials have yielded promising results, though the technology is not “100% finalised” yet.
Although fresh water is lacking in the region’s desert ecosystem and sand is in abundance, Kenawi says that sand is the larger obstacle to cost-effective fracking in the region. In the US, fracking typically requires sandstone or ceramic beads, which are not widely available in Saudi Arabia or the GCC. “One of the most important things to bring costs down to make the unconventional resources economical is using local sand, so our Saudi research and development centre focuses heavily on local sand,” Kenawi says.
He calls it “customised chemistry.” Grains of sands must be coated with chemicals so they can act as a proppant, propping open fracks to stimulate gas production. Halliburton is trying to get local sand to sustain the reservoirs’ compressive strength in order to keep fracks open to produce gas. “This will reduce the cost of production by 20% to 25%,” he says.
But localisation has a wide scope, and Kenawi says that Halliburton aims to localise as much work as possible, “from developing the technology and chemistry to manufacturing it and developing the people and their competency to frack a well.”
Its Saudi-based research and development centre near the reservoir means Halliburton can research and develop the necessary technology and chemistry close to the worksite, and the reaction plant that it is developing will allow it to manufacture those solutions nearby as well. This is all for the benefit of a lower cost per barrel of oil equivalent.
Still, cost-cutting runs deeper than local content, and in keeping with regional industry trends, Halliburton has an eye on digital technology for fracking. Reservoir modelling is key to improving productivity, as it allows operators to better understand their resources, the map of the reservoir, and the best locations to drill. But digital technology has seeped into the entire fracking process. Prodigi AB, launched in 2018, is one of its “digital frack” automation solutions—this technology takes real time measurements and with proprietary rate control algorithms, automatically adjusts pump rates and the number of density of perforation clusters per stage. The company says this technology can mitigate screen outs, a common source of frustration. “We believe this will make a change in how we can better place the frack and produce,” Kenawi says. “The second thing that we have is how we can make the equipment more reliable by digitising maintenance.”
Because of the high pressures and rates required of pumping systems for unconventional resources, maintenance and repair happen more frequently and can result in downtime. Predictive maintenance is an end goal for most oil and gas producers, which face a shared maintenance dilemma. Without predictive analytics, they wait for a machine to fail and then repair it, losing valuable production time, or they maintain their assets on a very regular schedule, even when the machine is functioning well, which could avoid downtime but adds the cost of unnecessary maintenance. For large producers with gigantic networks of assets, these costs add up.
Just as regional oil and gas companies have started to see the benefit of digitising their operations, they are opening their eyes to the possibility of maximising profits by selling the crude oil that would previously have been used for power generation, producing gas for internal use and as feedstock for the lucrative downstream segment, which provides balance for producers when oil prices are low. If the Middle East can leverage shale economically, this could be a tipping point into the region’s transition to gas.
“This is a huge opportunity,” Kenawi says. “If we do the whole cycle of reservoir insight, customised chemistry and surface efficiency in the Middle East, this would be a replication of what is happening in the US.”
The circumstances for the Middle East are certainly different than for North America, and a shale boom could yield different results, but regional NOCs no longer appear content with the status quo. Perhaps having noticed the success of the US shale revolution, they seem poised for a change of pace, and that is a revolution of its own.
