On fourteen dry, flat square miles of California’s Central Valley, more than 8,000 horsehead pumps—as old-fashioned oilmen call them—slowly rise and fall as they suck oil from underground. Glittering pipelines crossing the whole area suggest that the place is not merely a relic of the past. But even to an expert’s eyes, Kern River Oil Field betrays no hint of the technological miracles that have enabled it to survive decades of dire predictions.
When Kern River Oil Field was discovered in 1899, analysts thought that only 10 percent of its unusually viscous crude could be recovered. In 1942, after more than four decades of modest production, the field was estimated to still hold 54 million barrels of recoverable oil, a fraction of the 278 million barrels already recovered. “In the next 44 years, it produced not 54 [million barrels] but 736 million barrels, and it had another 970 million barrels remaining,” energy guru Morris Adelman noted in 1995. But even this estimate proved wrong. In November 2007 U.S. oil giant Chevron, by then the field’s operator, announced that cumulative production had reached two billion barrels. Today Kern River still puts out nearly 80,000 barrels per day, and the state of California estimates its remaining reserves to be about 627 million barrels.
Chevron began to markedly increase production in the 1960s by injecting steam into the ground, a novel technology at the time. Later, a new breed of exploration and drilling tools—along with steady steam injection—turned the field into a kind of oil cornucopia.
Kern River is not an isolated case. According to common wisdom, a field’s production should follow a bell-shaped trajectory known as the Hubbert curve (after the late Shell Oil geologist M. King Hubbert) and peak when half of the known oil has been extracted. Instead most of the world’s oil fields have revived over time. In a way, technology is the real cornucopia.
Many analysts now prophesy that global oil production will peak in the next few years and then decline, following the Hubbert curve. But I believe that those projections will prove wrong, just as similar “peak oil” predictions [see “The End of Cheap Oil,” by Colin J. Campbell and Jean H. Laherrère; Scientific American, March 1998] have been mistaken in the past. New exploration methods have revealed more of the earth’s secrets. And leaps in extraction technology have led to tapping oil in once inaccessible areas and in places where drilling used to be uneconomic. Advanced exploration and extraction methods can keep oil production growing for decades to come and could allow oil supplies to last at least another century.
Although oil and other fossil fuels pose risks for the climate and the environment, for now alternative energy sources cannot compete with their versatility, cost, and ease of transport and storage. As research into alternatives goes on, we will need to be sure that we use the oil we have responsibly.
All That You Can’t Leave Behind
At a time when the world increasingly fears an approaching peak and subsequent decline in oil production, it may be surprising to learn that most of the planet’s known resources are left unexploited in the ground and that even more still wait to be discovered.
On the face of it, oil should last only a few more decades. In 2008, just before the economic meltdown slashed consumption, the world burned about 30 billion barrels of oil a year. Assuming that in the near future consumption resumed at 2008 levels and then stayed constant, our planet’s proven reserves of oil—currently estimated at between 1.1 trillion and 1.3 trillion barrels—would have about 40 years to go.
But proven reserves are only estimates and not fixed numbers. They are defined as the amount of known oil that can be recovered economically with current technology, so the definition changes as technology develops and as the price of crude varies. In particular, if supply tightens or demand increases, resale prices go up, and oil that was once too expensive to extract becomes part of the proven reserves. That is why most oil fields have produced much more than the initial estimates of their reserves assumed and even more than the initial estimates of their total content. Today only 35 percent of the oil in the average oil field is recovered, meaning that about two thirds of the oil in known fields remains underground. That resource is rarely mentioned in the debate on the future of oil.
Even a mature oil country such as the U.S., whose oil production has been declining since the 1970s (if not as fast as the Hubbert curve predicted), still holds huge volumes of unexploited oil under its surface. Although the country’s proven oil reserves are now only 29 billion barrels, the National Petroleum Council (NPC) estimates that 1,124 billion barrels are still left underground, of which 374 billion barrels would be recoverable with current technology.
On a global scale, the U.S. Geological Survey estimates the earth’s remaining conventional oil (petroleum) deposits to be around seven trillion to eight trillion barrels. But with today’s technology, know-how and prices, only part of that oil can be recovered economically and is thus classified as a proven reserve.
And there is more.
Only one third of the sedimentary basins of our planet—the geologic formations that may contain oil—has been thoroughly explored with modern technologies. Moreover, the USGS data do not include unconventional oils, such as ultraheavy oils, tar sands, oil shales and bituminous schist, which together are at least as abundant as conventional oil.
Thus, a country or a company may increase its reserves of black gold even without tapping new areas and frontiers, if it is capable of recovering more oil from known fields. Still, doing so is not always easy.
A Rocky Start
Contrary to common belief, oil is not held in great underground lakes or caves. If you could “see” an oil reservoir, you would notice only a rocky structure seeming to have no room for oil. But beyond the reach of the human eye, a world of often invisible pores and microfractures entraps minuscule droplets of oil, together with water and natural gas.
Nature created these formations over millions of years. It started when huge deposits of vegetation and dead microorganisms piled up at the bottom of ancient seas, decomposed and became buried under successive layers of rock. High temperatures and pressures then slowly transformed the organic sediments into today’s oil and gas. These fossil fuels soak the porous underground rock almost like water soaks pumice.
When such a reservoir is drilled, it behaves a bit like an uncorked bottle of champagne. The oil is freed from its ancient rocky prison, and the reservoir’s internal pressure pushes it to the surface (along with stones, mud and other debris). The process goes on until the pressure peters out, usually after several years. This initial, or primary, stage of recovery can usually yield between 10 and 15 percent of the oil in place. From then on, recovery must be assisted.
About one third of the oil left in a reservoir after the initial “champagne” release is called immobile oil—drops trapped by strong capillary forces within isolated pores in the rock. No technique exists yet to extract this part of the oil. The remaining two thirds, though mobile, will not necessarily flow into the wells on its own. In fact, usually about half of the mobile oil stays stuck inside the reservoir because of geologic barriers or low permeability, which happens when the pores are too narrow. The situation is even worse when the oil is not a light liquid but a heavy, viscous, molasseslike substance.
To help some of the remaining oil seep through the pores in the rock and come out of the wells, operators usually inject natural gas and water into the reservoir, in what is called secondary recovery. Injecting gas restores the lost pressure and forces oil that is sufficiently fluid to seep through the rock’s pores. Meanwhile, because oil is lighter than water, injection of water raises the oil toward the well, just like pouring water in a glass filled with olive oil would send the oil upward.
In the past decade or so, the distinction between primary and secondary recovery has blurred as companies have begun to apply advanced technology from the outset. One of the most important developments so far has been the horizontal well, an L-shaped structure able to deliver dramatically more oil than the traditional vertical drilling that has been used since the inception of the oil industry. The L shape enables horizontal wells to change direction and penetrate sections of a reservoir that would otherwise be unreachable. The method, first adopted commercially in the 1980s, is particularly suitable in reservoirs where oil and natural gas occupy thin, horizontal layers.
Exploration tools have also improved over the years. Advanced 3-D imaging of the underground, for instance, which is based on how seismic waves bounce off the boundaries between layers of different rock composition, now offers more detailed understanding of the structure of existing fields, which helps in choosing where to drill to optimize recovery.
Imaging technologies now enable geologists to “see” what lies underneath layers of salt that sit unevenly distributed below the seabed and are sometimes thicker than 5,000 meters. Similar to frozen waters, salt formations used to represent a formidable obstacle because they blurred the seismic waves used to reconstruct an accurate image of the underground.
Such imaging breakthroughs, combined with more advanced offshore technologies, have made new parts of the oceans accessible to oil developers. At the time when the North Sea oil fields were developed in the 1970s, it seemed as if offshore technology had reached its most daunting milestone, tapping fields that lay below 100 to 200 meters of water and 1,000 meters under the seabed. But in the past few years the industry has succeeded in striking oil at depths below 3,000 meters of water and 6,000 meters of rock and salt. There have been at least three major ultradeep offshore discoveries: Thunder Horse and Jack in the Gulf of Mexico and Tupi off the coast of Brazil.
Scraping the Barrel
As wells have gone farther and deeper than ever before, technologies have also evolved to get more oil out of the rock after the first lines of recovery have run their course. Primary and secondary recovery stages together can bring the recovery rate to between 20 and 40 percent. To go beyond that, in what experts call tertiary recovery, it is usually necessary to make the remaining oil less viscous, which can be accomplished using heat, gases, chemicals and even microbes. Steam injection, among the oldest heat-based methods, was decisive in the revival of the Kern River Oil Field back in the early 1960s. The injected steam heats the overlying formation and enables oil to move. To this day, Kern River’s steam-injection project is among the largest of its kind in the world. A variant of steam-assisted recovery has been applied to tar sand deposits in Alberta that are too deep to be surface-mined.
Another heat-based process that has been tested in the field is burning a part of the reservoir’s hydrocarbons by igniting it with a heater while pumping air into a well to feed the combustion. The fire generates heat and carbon dioxide (CO2), both of which make oil less viscous; much of the CO2 also remains underground and helps to push the oil out. At the same time, the fire itself breaks the larger and heavier molecules of oil, once again making it mobile. The airflow can be controlled to limit oil that gets burned and to prevent the release of pollution into the surrounding environment.
A more common method is the high-pressure injection of gases such as CO2 or nitrogen into the reservoir. These gases can restore or maintain a reservoir’s pressure and can also mix with oil, reducing both its viscosity and the forces that can keep the oil trapped. In the U.S., CO2 extracted from volcanoes or from waste gases from power stations has been applied to oil recovery since the 1970s. The process is in use in about 100 ongoing projects, with dedicated pipeline networks totaling more than 2,500 kilometers.
The know-how accumulated in CO2 injection has opened the way for the capture and storage of CO2 from power plants—procedures that could help slash emissions of this greenhouse gas into the atmosphere and instead keep it underground for hundreds of years. The first commercial carbon capture and storage project has been active at the Sleipner field, off the coast of Norway, since 1996, and is storing one million metric tons of CO2 a year. This amount is small, considering that human activity alone is estimated to eject into the atmosphere greenhouse gases equivalent to around 50 billion metric tons of carbon dioxide every year. But the plant’s success serves as a proof of concept.
Ironically, however, one of the main problems with using CO2 for oil recovery is its scarcity. Capturing the gas from power station smokestacks or volcanoes is not cheap, and the cost of capturing it from smaller sources, such as cars or even most industrial plants, is prohibitive. Another hurdle is transportation, which can be too costly if the oil fields are in remote regions.
Chemistry-based recovery is a more recent strategy. Certain chemicals can mix with trapped oil and make it less viscous, so that it can flow toward the well. These substances all work on the same principle, which is similar to how layers of soap molecules engulf fatty substances and work to remove grease from your hands. The most successful chemical process also increases the viscosity of the underground water, which helps the water push the oil toward the wells without reaching the wells first. At China’s Daqing oil field, this process is credited for getting out an extra 10 percent of the reservoir’s oil since the mid-1990s. And in one version of the process, a caustic solution generates the soaplike materials from components present within the oil itself, limiting the overall cost.
Microbial enhanced oil recovery is still in its infancy, with experiments under way in the U.S., China and other countries . Engineers pump vast amounts of specialized microbes into the reservoir, together with nutrients and, in some cases, oxygen. The microbes grow in the interface between the oil and the rock, helping to release the oil. Genetic engineering opens up the possibility of modifying bacteria and other microorganisms to make them more efficient at aiding oil recovery.
None of these advanced recovery techniques is particularly cheap. But some (notably CO2-assisted recovery, if a source of the gas is easily accessible nearby) are already economical as long as the price of crude stays above $30 per barrel, and most, including chemistry-based recovery, become economical at around $50 per barrel.
“Easy oil” is running out, probably because it was the first to be discovered and burned. Many of the largest and most productive oil basins in the world are approaching what I call technological maturity, which is when traditional technologies stop being effective. These basins include reservoirs in Persian Gulf countries, Mexico, Venezuela and Russia that started yielding oil in the 1930s, 1940s and 1950s. For these fields to keep producing in the future, new technologies will be required.
But “easy oil” wasn’t so “easy” when it was discovered. By the same token, the difficult oil of today will be tomorrow’s easy oil, thanks to the learning curve of technology expertise. Technological breakthroughs in the oil industry have always been the result of long, drawn-out processes. Horizontal drilling was first tested in the 1930s, and some of the more advanced recovery methods have existed at least since the 1950s. For most of the industry’s history, however, oil has been overabundant, so its price has been too low to justify significant and costly innovations. But a new era is coming in which new technologies will be adopted at a faster pace.
The move toward increased recovery rates may be slowed down by the current wave of resource nationalism. Whereas in the early 1970s the major oil companies controlled around 80 percent of global oil reserves, today more than 90 percent of the world’s conventional oil is under the direct control of producing countries, through their national oil companies. But the uncertain future of the demand for oil makes some of these countries reluctant to invest in modern technology and in exploration, especially because making significant investments means taking resources away from social and economic development programs.
Still, I dare to make a prediction. By 2030 more than 50 percent of the oil known at the time will be recoverable. Also, by that time the amount of known oil will have grown significantly, and a larger portion of unconventional oils such as oil shales will be commonly produced, bringing the total amount of recoverable reserves to something between 4,500 billion to 5,000 billion barrels of oil. A significant part of the “new reserves” will not come from new discoveries but from a new ability to better exploit what we already have.
To be sure, by 2030 we will have consumed another 650 billion to 700 billion barrels of our reserves, for a total of around 1,600 billion barrels used up from the 4,500-billion to 5,000-billion figure. Yet if my estimates are correct, we will have oil for the rest of the 21st century. The real problem will be how to use the remaining oil without wasting it through unacceptable consumption habits and—above all—without endangering the environment and climate of
Note: This article was originally printed with the title, "Squeezing More Oil From the Ground."