On March 5, 2007, The New York Times published an article entitled “Oil Innovations Pump New Life Into Old Wells,” by Times correspondent Jad Mouawad.
The title of the article referred to recent increases in oil extraction from older oil fields, noting: “Within the last decade, technology advances have made it possible to unlock more oil from old fields, and, at the same time, higher oil prices have made it economical for companies to go after reserves that are harder to reach. With plenty of oil still left in familiar locations, forecasts that the world’s reserves are drying out have given way to predictions that more oil can be found than ever before.” As is the case with much of what gets published in The New York Times, some of the information in the article is true. But then again, to the well-trained and highly polished Peak Oil mind, the article has a lot of disinformation in it about what is the long-term state of the oil patch. In a not-so-subtle manner, the Times article appears to diminish the credibility of the Peak Oil argument. Specifically, the Times article focuses on allaying any Manhattanite fears of future scarcity of conventional oil by suggesting that “new technology” will locate and extract immense volumes of oil with which mankind will, to all intents and purposes, power its way into a brighter future.
It is as if we can now all kick back, pop a beer, wipe the sweat from our collective brow, and say, “Whew, we dodged that Peak Oil bullet.” Porosity, Permeability, Rocks, and Reserves The “world’s reserves are drying out,” states the article. I would not put it quite that way. Oil reserve estimates are a complex mixture of science and art, but the aggregate number depends in large measure on price. Reserve estimates do not really “dry out.” Estimates or volumes or quantities may rise or fall, but there is nothing dry about them, except for the Securities and Exchange Commission rules that govern how publicly traded oil companies have to do the underlying engineering-based accounting.
And is it true that, as the article states, “more oil can be found than ever before”?
No, not exactly.
The oil in older oil fields has, of course, by definition, already been found. The oil may or may not have been extracted and recovered, but it has been found. Getting it out is the problem, and for that we have to drill holes into the rocks. Always have, and always will. Oil, and associated natural gas and water, accumulates in what are known as “reservoir” rocks over periods of geologic time, meaning very long time periods often as not measured in millions of years. Reservoir rocks are almost always sedimentary rocks that have a fortuitous combination of what is called “porosity” and “permeability.” (In rare locales, such as offshore Vietnam, metamorphic, and even igneous, rocks serve as reservoir rocks. The oil originated elsewhere, and has migrated into porous, permeable metamorphic or igneous rocks. We will address the migration process shortly.)
The porosity of a rock is a measurement of the volume of the (usually) microscopic “pore” spaces between the mineral grains that make up the bulk of the rock. And the permeability of a rock is a measurement of the ability of a fluid to flow through these small pore spaces. (Just to be clear, oil is not located in big, empty voids deep within the earth. There are no natural “pools” of oil, like gigantic underground swimming pools, waiting for someone to drill and pump the oil out.) But a reservoir rock also needs some sort of “cap,” or trapping mechanism, to hold the oil inside its pore spaces. Over geologic time, even very minor leaks (along, say, fractures or faults) can allow essentially all of the fluids, and certainly the valuable ones like petroleum, to drain out of a rock formation. Rock formations such as salt beds or tight, very impermeable shales often serve as cap rocks, keeping the petroleum fluids sealed within the reservoir rock. And all of this assumes that somewhere nearby is a “source” rock, from which the oil and natural gas originated.
Usually, the source rocks are located in close proximity to the reservoir, but not always. In some of the conventional oil fields of Western Canada, for example, the source rocks are as much as 100 miles from the reservoir rocks, indicating quite a long migration to their ultimate resting place. So the oil that lubricates and powers the world originated during various geological periods of the past and came to be formed in source rocks. Eventually, and subject to a multitude of geologic forces and phenomena acting over relatively long periods of time, the oil migrated from the source rocks into permeable reservoir rocks. As the oil flowed through these reservoir rocks, it came to occupy the pore spaces within the grains that make up the underground oil reservoir. Some sort of cap, or other lithologic seal, kept the oil in the reservoir rocks, awaiting discovery in the years since Col. Drake ushered in the modern Age of Petroleum, starting in 1859 at Titusville, Pa. This oil in the ground is usually called the “original oil in place” (OOIP). Gushers and Blowouts While we are on the subject of oil in the reservoir (or OOIP), I should mention that in order for the oil to be able to migrate into a drill hole, there is a requirement for “reservoir energy.” That is, some form of energy has to be present within the reservoir rock to cause the OOIP to move from the pore spaces where it has resided for these many years into a hole in the ground. Reservoir energy can be present due to the fact that most oil contains dissolved natural gas, usually under pressure, and in some locales under great pressure. (I write from personal experience on this one.) So the oil, with the “higher pressure” gas dissolved within, tends to flow, via that above-noted permeability, through the pores of a rock formation and into the “lower pressure” hole that the drillers have put down into the ground. The aboveground analogy would be the carbon dioxide (CO2) gas dissolved in a bottle of soda pop. When you remove the cap from the bottle, the dissolved gas starts to fizz towards the low-pressure open end of the bottle.
In the olden days, when people who drilled for oil did not quite understand the process, they would drill down into a rock formation and the reservoir energy would overwhelm the hole in the ground. This ofttime led to a rapid explosion of pressurized oil from the ground, famously known as a “gusher.” The old movies and photos show people acting happy, and even dancing with joy when a well “gushed.” But unbeknownst to the early oil pioneers, this was a disastrous waste of the reservoir energy of the oil field, because it caused the dissolved gas rapidly to exit from the reservoir rock and leave much of the otherwise recoverable oil behind. Thus, much of modern petroleum engineering has to do with monitoring and maintaining reservoir pressures as high as possible for as long as possible during drilling and producing operations, so as to recover as much of the OOIP as is possible. And yes, things like gushers can still happen in today’s highly engineered world, but we call them “blowouts.” They are not happy occasions. Neglected Resources: 2 out of 3 Barrels The New York Times article further discussed the process of oil recovery, stating: “Typically, oil companies can only produce one barrel for every three they find. Two usually are left behind, either because they are too hard to pump out or because it would be too expensive to do so. Going after these neglected resources, energy experts say, represents a tremendous opportunity. “‘Ironically, most of the oil we will discover is from oil we’ve already found,’ said Lawrence Goldstein, an energy analyst at the Energy Policy Research Foundation, an industry-funded group.
‘What has been missing is the technology and the threshold price that will lead to a revolution in lifting that oil.’” This description makes it seem like oil companies have always had more control over what happens than is actually the case. “Too hard to pump out,” states The New York Times article. Well, sort of. What the article is attempting to describe is the process whereby, over time, about one-third of the conventional oil in a given reservoir migrates from its geological location to the drill hole. The reason that it migrates is because of that above-noted reservoir energy. Think of the high pressure oil (or at least, the “higher” pressure oil) moving towards the low-pressure drill hole. This migrating oil is that one barrel out of three, on average. (Some oil fields yield higher percentages of the original oil in place. Other oil fields yield far lower percentages.) By the time that the one barrel makes its way to the borehole, the reservoir energy has diminished to the point that it is not sufficient to mobilize the other two barrels. So that oil remains behind, in the reservoir rock formation.
For most of the history of the oil industry, oilmen have been at the mercy of the reservoir energy in the rock formations deep beneath their feet. If you were fortunate enough to locate low viscosity oil with a high measure of reservoir energy, then you could extract a high percentage of the OOIP. Col. Drake’s first well at Titusville, for example, produced a “Pennsylvania” grade of crude oil that was exceedingly slippery (i.e., low viscosity, such that it feels smooth like hand lotion) from a thin, porous sandstone with excellent permeability, and the reservoir energy that benefited Col. Drake was what is called “water drive.” That is, ground water was essentially pushing the oil from the rock formation into Drake’s 69-foot-deep hole in the ground. Under these circumstances, recovery of OOIP from the sandstones beneath the Titusville region was relatively high over the years.
Enhancing the Reservoir Energy At the other end of the oil patch spectrum, however, the Kern River oil field, discovered in 1899 near Bakersfield, Calif., yields a highly viscous sort of oil, loosely described as “heavy oil.” There was never all that much reservoir energy to begin with, so the original rates of recovery of OOIP were in the range of perhaps 10%. In other words, nine out of 10 barrels of OOIP were left in the rock formation. But in recent years, as The New York Times notes in its article, Chevron has been using steam-flood technology and computerized 3-D reservoir modeling to boost the output of the Kern River field’s heavy oil reserves.
For something over two decades, Chevron engineers have injected high-pressured steam into the oil reservoirs, to enhance the reservoir energy and to mobilize the oil. This has allowed Chevron to pump out more oil. Production from the Kern River field had slumped to about 10,000 barrels a day in the 1960s, but with the steam flood, it now has a daily output of about 85,000 barrels. And even after a century of production, Chevron engineers say there are many more years of productive life left in the field, and much more oil to be pumped from Kern River, although all the steam in the world will not prevent the inevitable phase of irreversible decline in production over time.
According to The New York Times article: “At the Kern River field…millions of gallons of steam are injected into the field to melt [sic] the oil, which has the unusually dense consistency of very thick molasses. The steamed liquid is then drained through underground reservoirs and pumped out by about 8,500 production wells scattered around the field, which covers 20 square miles. “Initially, engineers expected to recover only 10% of the field’s oil. Now, thanks to decades of trial and error, Chevron believes it will be able to recover up to 80% of the oil from the field, more than twice the industry’s average recovery rate, which is typically around 35%. Each well produces about 10 barrels a day at a cost of $16 each. That compares with production costs of only $1 or $2 a barrel in the Persian Gulf, home to the world’s lowest-cost producers.” While there is nothing objectionable about what The New York Times article states, the article misses an important point with those “millions of gallons of steam.”
There are immense amounts of energy involved in generating the steam that goes into the ground, and this is one of the reasons why Kern River oil is up to 16 times more costly to produce than Persian Gulf oil. And not to quibble, but pumping steam is not exactly new or revolutionary technology. Oil well drillers near Titusville were documented as pumping steam down well bores as early as 1862, at first in an effort to remove the paraffin wax that built up inside the well casings. Then, over time, people noticed that a “steam bath” tended to give a kick to subsequent production. These old drillers may not have understood the engineering aspects in any detail, but they knew what worked out in the field.
Then as now, making steam required boiling water, which required more capital investment, equipment, energy, and labor, so it drove up costs. Plus, making and pumping steam added to the danger of working in the oil patch, and it was dangerous enough to work just around oil wells with no hot steam pipes crisscrossing the landscape. So the steam-pumping process added even more potential for leaks, sparks, and explosions. Thus, for many years steam pumping was used only in exceptional circumstances. As long as oil was cheap and relatively available from other oil fields in other locales, there was no particular incentive to add more layers of complexity to a process that was difficult enough on good days. But above a certain price for a barrel of oil, the extra cost of steam, or other methods of enhanced oil recovery, can pay for itself.
The New York Times article noted that the Kern River is… “Littered with a forest of wells, with gleaming pipes running along dusty roads. Seismic technology and satellites are now used to monitor operations, while sensors inside the wells record slight changes in temperature or pressure. Each year, [Chevron] drills some 850 new wells there… “There are very few workers in the field. Engineers in air-conditioned control rooms can get an accurate picture of the field’s underground reservoir and pinpoint with accuracy the areas they want to explore. None of that technology was available just a decade ago.” What a Difference a Decade Makes No, a decade ago, oil was selling for as little as $10 per barrel. And the Kern River field was a high cost outpost of marginal wells that produced viscous oil that was (and still is) hard to handle and refine. But things have changed, and now the place is booming. Worldwide, reserves of conventional oil, also known as the “easy” oil, are declining and not being replaced. Oil companies, from the likes of large majors like Chevron to the national oil companies (NOCs) of many nations, are looking further afield for oil supplies, and are also looking at older areas to attempt to recover what they left behind the first time around.
In some areas, old oil fields that were long ago abandoned and plugged with concrete are being drilled again. “There are finite resources in the ground, but you never get to that point,” states Jeff Hatlen, an Chevron engineer, in a discussion with the reporter from The New York Times. “Peak Oil is a moving target,” Mr. Hatlen said. “Oil is always a function of price and technology.” Price, Technology, Time, and Depletion Yes, oil is a function of price and technology. But oil is also a function of time and depletion. So over the long term, and as existing reserves deplete, we have to ask the question, “What price and what technology?” That is, how much are people willing to pay, and for what kinds of equipment, to recover oil from the ground? Of course, every good business student learns early to ask, “What is the return on investment?” But the next question, that far fewer people even understand how to ask, is “What is the energy return on energy investment (EROEI)?” How much can anyone pay, and what measure of resources is it worth to get to that last marginal barrel? And the ultimate question is, “Can price and technology move the marketplace for energy faster than oil reserves are declining in the face of depletion?” We are, of course, all going to find out, should we live so long.
Until we meet again… Byron W. King