Organic acids — including acetic acid, commonly known as vinegar — are routinely found in water that is pumped from underground oil reservoirs. Exactly how these acids relate to the generation of petroleum isn't altogether clear; but oil companies have long suspected that if the acids were properly analyzed, they could yield useful clues about the petroleum "systems" from which they are drawn.
"These acids are hard to get at analytically," says Robert Dias, a doctoral student in geo-chemistry at Penn State. "They typically exist in very low concentrations, and they're chemically volatile. Extracting them from water can alter them."
Finding a way over this hurdle is one of the reasons Dias left a job in the oil industry to come to graduate school and work with Penn State geoscientist Katherine Freeman. One of Freeman's specialties is analyzing organic matter according to the isotopic composition of its carbons.
Carbon has two stable isotopes in nature, Dias explains: 12C and 13C. Although the two are identical, chemically speaking, at the subatomic level they are slightly different. "Carbon 13 has one extra neutron."
The isotopic composition of the carbon in a substance, Dias continues, specifically the ratio of 13C to 12C it contains, can be an important key to how that material was formed. "Biological, chemical, and physical processes will all separate carbon isotopes," he says. In the case of evaporation, for example, "under normal conditions, the lighter isotope, carbon 12, typically goes off first."
In his first year with Freeman, Dias worked on developing a technique for pinpointing the 13-12 ratio in organic acids dissolved in water. The simplest and best approach, they found, is one called solid-phase micro-extraction.
Dias picks up an instrument that looks like a syringe. The glass-fiber needle on its end, he explains, can be coated with different organic phases — thin layers of solid material intended to adsorb, or grab hold of, specific molecules in solution. "For this purpose," he says, "we use a phase that is attractive to organic acids." The syringe is dipped into a glass vial containing a sample of oil-related water and left there until the water's organic components latch on. The needle is then retracted and inserted into a gas chromatograph, where it is heated until the organic components clinging to its surface desorb into a stream of carrier gas. This gaseous mixture then flows into a spiral chromatographic column where its components are separated out according to their different masses and chemical properties. "What we end up with," Dias says, "is a well-resolved spectrum of compounds. From that we can get the carbon isotope ratio."
When they heard about the new technique, researchers from the Atlantic Richfield Company contacted Freeman looking to test it on a specific petroleum basin. ARCO had already determined that the basin contained two source rocks, each generating a slightly different type of petroleum. Without telling them what they knew, the ARCO scientists mailed Freeman and Dias water samples drawn from wells in the area. "We went into it blind," Dias says. "They wanted to see what we could tell them."
Dias ran his analysis for carbon-isotope values, got his results, and called his ARCO contact on the phone. "I was able to tell him that there were either two sources in this basin, or one source with two reservoirs that were separated by a fault, with no communication between them."
Dias smiles. "At that point there was about 30 seconds of silence on the other end of the line. Then the guy says, 'How the heck did you know that?'"
A doctoral dissertation was born. Dias contacted Mike Lewan, a colleague at the United States Geological Survey in Denver who has an experimental setup for simulating the generation of oil.
In nature, making oil takes millennia, as decayed organic matter turns to petroleum, is squeezed from the rocks it formed in, and eventually finds its way into reservoirs made in more porous material. Lewan can recreate the process, on a Lilliputian scale, in 72 hours. "He seals up immature source rocks and water in a reactor drum, heats it to 200 or 300 degrees C, and leaves it over a weekend," Dias says. Temperature takes the place of time, and on Monday morning, Lewan ends up with a layer of spent source rock, a layer of water with organic acids in it, and, atop that, a layer of oil.
Dias analyzed samples of the water produced by six different types of source rock in Lewan's reactor, and got six very different carbon-isotope values. "This gave us some idea of the range of values that might be found in nature," he says. He also found that for any one source rock, there were large swings in the 13C—12C ratio depending on the temperature to which the reactor had been heated and the molecular weight of the organic acid. He knew then that he was on to something valuable.
"This gives us an internal molecular marker to tell how a compound was generated, what it reacted with, and how it was destroyed," Dias explains. By means of a simple test, in other words, he can discern what type of rock and what types of geologic processes produced the oil-related acids in a given water sample. "This is potentially a very important tool for oil exploration and reservoir development," he says. "It can give reservoir engineers a better idea of the nature of the petroleum system they're dealing with, without their having to have a sample of oil."
Robert F. Dias is a Ph.D. student in geosciences in the College of Earth and Mineral Sciences, 801 Deike Bldg., University Park, PA 16802; 814-865-1178; rfd116 @psu.edu. His advisor is Katherine H. Freeman, Ph.D., associate professor of geosciences, 209 Deike Bldg.; 863-8177; khf4@psu.edu. This work was partially supported by the Atlantic Richfield Company (ARCO). The solid-phase micro-extraction instrument described above, known as an SPME, was developed for commercial sale by Supelco of Bellefonte, PA.