By Alyona Zhuravlyova
Fracking technology has been used in the oil industry for more than 50 years. Throughout that period, debate has raged on about its benefits and shortcomings. Some point to limitations in using it owing to high costs, others decry the environmental damage it inflicts, still others talk about the indisputable advantages it offers in extracting oil that without fracking would otherwise remain in the ground.
There is no dispute about one thing – that fracking upended the entire energy landscape throughout the world, particularly in the United States.
It was Soviet academics who stood behind the creation of fracking technology, devising the theory of creating and expanding two-dimensional fissures in rock strata. But the first example of commercial fracking was conducted in the United States by the Halliburton company in 1949. The method was in use in the Soviet Union from 1952, but subsequently fell out of use as extraction began on the vast oil deposits of western Siberia.
Fracking – the core idea
Fracking allows for the extraction of oil located in difficult-of-access areas with low permeability into reservoirs separated from each other. The basic idea of fracking is to proceed with high-pressure injection of liquid into rock strata, resulting in a break in the rock and the formation of cracks through which oil will make its way into a well. A fixing or thickening agent is added to the liquid to ensure that the cracks do not give way until the pressure of the rock stratum.
Fracking can be used with “proppant” – the injection into the rock stratum of a wedging material that keeps the cracks from closing up. Or acid can be used as the liquid to create the fissures.
In Russia, shale oil is divided into two categories – tight oil and shale oil.
Tight oil is located in areas with low permeability, while shale oil is kerogen, solid insoluble organic matter in shale rock formations, known as “high-viscosity oil”.
The geological make-up of the reservoirs is such that more wells must be drilled to extract shale hydrocarbons than for traditional extraction – and they must be closer together. And the wells have a much shorter operating life – about three years compared to 10. That drives up costs.
The golden ticket for shale reservoirs
Longstanding reserves of oil and gas are running out, hydrocarbon extraction is becoming increasingly difficult and expensive using standard methods, but demand for oil is on the rise (without taking account of the effects of COVID this year).
The oil industry was obliged to shift its focus to so-called non-traditional reserves in difficult-of-access deposits. Shale oil is light and low in sulfur content, but lies in areas with low permeability.
Shale is very dense and made up of sandstone and limestone — oil cannot pass through it. Traditional methods of extraction do not work in such reservoirs as oil cannot flow through them to the well. And shale strata could be horizontal, at an angle or at various different depths.
Companies extracting shale oil combine two types of technology – fracking and horizontal drilling. A traditional vertical well is first drilled and when the depth of the deposit is reached, it then turns horizontal. And a vertical well can branch out into several horizontal or diagonal wells. Fracking then proceeds – several thousand tonnes of water is introduced under pressure, mixed with chemical compounds and proppant – sand or synthetic substitutes.
Companies can use fracking with multiple stages when operating on different sections of a single well. Selective fracking technology is used to limit the environmental effects and to ensure the cracks are not breached. And to ensure that the proppant remains in the fissure, fibre is pumped in, along with liquids aimed at keeping the rock strata free of pollutants.
And to ensure against errors, a company can conduct “mini fracking” before proceeding with the actual fracking operation. That enables engineers to examine the properties of the rock and select an appropriate level of pressure, in essence a model to help fissures or cracks develop and establish how they should look.
A type of “mass fracking” technology can also be used for reserves with very limited permeability—fissures in cases using this technology can be 1 km in length and the volume of liquid to be pumped into them can reach several thousand cubic metres. To speed up the flow of hydrocarbons through the rock, a liquid-gas mix with nitrogen can be pumped into the fissure.
But even with the wide variety of fracking techniques and technological applications for shale projects, there are no universal rules of usage – an individual combination must be selected for each site.
A shale revolution – at what cost?
The shale revolution took hold in the United States thanks specifically to the mass use of fracking technology and horizontal drilling. Companies initially concentrated on gas and then branched out into shale oil. Extraction of shale oil began in the 2000s in the Bakken oil field in North and South Dakota and Montana with production levels reaching 600,000 barrels per day in 2012.
Production figures rose dynamically and from 2010, more than half of all wells in the world were drilled in the United States, making the country the world’s biggest oil producer.
But the growth in production also exposed problems within the sector.
The issue remained that shale oil production was still a costly venture, in part because greater numbers of wells were required. And a year after the fracking process is carried out, extraction levels are cut in half and a well can remain in operation for about three years.
After that, extraction becomes unfeasible. New wells have to be drilled. And the deeper the rock strata, the more costly the already expensive processes of fracking technology and horizontal drilling become.
The main issue lies with the financing of shale companies which underpinned the shale revolution on the basis of large-scale borrowing. According to analysts Rystad Energy, over the period 2008-2018, shale producers spent $400 billion of outside capital and could hardly turn a profit.
Against this background, borrowing costs continued to rise and the onset of the COVID pandemic made access to “easy money” increasingly difficult for producers.
A decline in demand for oil, a halt to drilling at many projects, the rising costs of capital, the reluctance of investors to put money into the oil industry and a growing shift to renewable energy sources merely added fuel to the fire.
Oil expert Daniel Yergin, quoted by the Financial Times, said the shale industry needed a second revolution even before the pandemic struck.
“It needed a revolution in terms of its relationship with its investors,” Yergin was quoted as saying.
According to a forecast by the International Energy Agency, investment in the U.S. shale industry could plunge this year to $45 billion – less than half of last year’s level of $100 billion. At its peak in 2014, the volume of investment had reached $145 billion.
The IEA believes that over the next decade average annual levels could stand at $85 billion.
In theory, shale industry production levels could be restored by 2022, but a recovery could be hit by an absence of cheap credits. Company ratings are on the decline and that means borrowing costs are on the rise. The IEA estimates that borrowing costs for shale companies rose by about four percentage points this year – to 12 % from 8 %. Smaller players simply cannot survive a crisis of this magnitude and combined efforts are required.
The wave swallows up everyone
A succession of huge deals and mergers has overwhelmed the American market.
Back in July, it was announced that Chevron was buying Noble Energy in a deal valued at $5 billion – though it was conducted in the format of an exchange of shares – a Nobel Energy share was valued at 0.1191 Chevron shares and that totalled about 3 % of the merged company.
Nobel Energy shareholders endorsed the deal in the autumn and matters are to be completed by the end of the year. Noble Energy deals with exploration and extraction of hydrogens, with assets in the United States, on the shelf of the Eastern Mediterranean and in Africa.
In September, a merger was announced between two independent American shale gas producers – Devon Energy and WPX Energy.
This deal was also devised in cashless form – WPX shareholders will receive 0.52 Devon shares for each share of their own, with the deal valued at $2.5 billion. The new company will be valued at $12 billion – Devon’s current shareholders will receive 57 % of the merged company, with WPX shareholders receiving 43 %. Both sides intend to complete the deal by early next year.
ConocoPhillips then confirmed rumours by announcing in October that it was buying Concho Resources – a company specialised in producing shale oil. The deal was valued at $9.7 billion and is likely to be one of the largest deals this year on oil markets. ConocoPhillips will become the largest independent oil company in the United States, with daily production of 1.5 million barrels.
The plans call for Conoco to assume Concho’s debts of about $4 billion. It will cover the cost of the deal with its own shares – every Concho share will receive 1.46 Conoco shares. The new company’s capitalisation will total $60 billion – the third largest in the country. Concho Resources is the fifth largest producer in the Permian Basin in the southwestern United States – 319,000 barrels per day. The companies are to complete the deal by the first quarter of next year.
In clinching the deal, Conoco showed yet again that in these new conditions only large companies can survive.
Pioneer Natural Resources agreed to acquire all shares of its competitor Parsley Energy for about $4.5 billion in addition to assuming responsibility for its debts. The overall sum is estimated at $7.6 billion and the new company will produce 558,000 barrels of oil equivalent per day.
It was subsequently announced that EQT, already the country’s largest gas supplier, was seeking a takeover of its competitor CNX Resources. The two companies are viewed as the largest players in the Marcellus Shale producing region in the eastern United States.
In addition, Gas producer Southwestern Energy bought Montage Resources, which operates in the shale-producing areas of Utica and Marcellus. It also assumed responsibility for all its debts.
Southwestern’s gas production level will now stand at about 3 billion cubic feet per day.
Analysts Rystad Energy estimated the debts of North American oil producers have reached record levels and will exceed $100 billion by the end of the year.
Experts believe that 55 companies in the sector will declare bankruptcy and that will only speed up the sector’s consolidation. As a result, about 10 large share producers will be responsible for half the capital investment in the sector over the next five years.
And investors are becoming increasingly selective about the assets they intend to acquire and seek out only top-quality projects. Sellers are trying to shed assets with limited prospects and buyers want to clinch advantageous deals which will enable them to earn money quickly.
Rystad said large companies like ExxonMobil, Chevron, ConocoPhillips, BP, Shell Total, Eni and Equinor will end up selling oil and gas projects with a combined production level of 68 billion barrels and valued at $11 billion. And deals involving share exchanges are possible in order to create combined portfolios.