Biomarkers and carbon isotopes can be used to backtrack migrated hydrocarbons to the source rocks so an operator would know where to put a lateral for optimum production. Since plays such as the Niobrara and Mowry cover vast acreage, an operator needs to be able to fine tune where hydrocarbon generation and migration occurred.

“We are looking at what we call biomarkers and carbon isotopes of various molecules in the oil to determine a lot of geological information,” John Curtis, director, Potential Gas Agency, Colorado School of Mines, said at the Hart Energy 2013 DUG Bakken conference in Denver May 31. “For example, we can get information on source rock type and what kind of lithology it is, such as carbonates, clastics, or marls.”

A biomarker is nothing more than a hydrocarbon molecule that can survive. “Usually there are 20 or more carbon atoms per molecule, and we call them molecular fossils,” he noted. “These are hydrocarbons whose structures can be recognized in living organisms, occur in some reasonable abundance in nature, and are stable during diagenesis.

“Using carbon isotopes, you can actually age-date the oil. You can look at the biomarkers – those little fingerprints and tracers – and determine in what age that oil was generated and the age of the organic matter that generated the oil,” he continued. “We can get information from the oil on the maturity of the organic matter that generated it. Company management is particularly interested in thermal maturity since this can tell them whether to expect gas, nice light oil that will flow, or condensates.”

“This is work that has been known for a number of years. Using geochemistry complements standard geological and geophysical work and provides molecular-level detail for exploration,” he added.

Curtis used work being done on the Niobrara and Mowry formations and a third marine shale in both the Upper and Lower Cretaceous in the Powder River, Denver, Laramie, and Park basins to demonstrate the value of geochemistry in determining depositional environments and migration timing, distance, and direction.

The biomarkers and isotopes were divided up into five families in the Rockies. Curtis has worked with GeoMark Research Ltd. in these studies with about 1,600 oils in this dataset. The Mowry is at the top of the Lower Cretaceous and the Niobrara is at the top of the Upper Cretaceous. The five families are Cretaceous marine shales, including the Mowry and Niobrara; deltaic/parolic shales; Paleozoic shales and marls; Green River formation marls; and the Permian Phosphoria formation.

Determining Migration

When oil is generated, it locks in its source rock. Then the source rock can be identified by backtracking to where it came from by identifying the daughter oil, Curtis said. Biomarkers can be used to determine depositional environment. For example, terpanes, which are from bacteria, can be used to indicate upwelling in the depositional environment.

“The Western Interior Cretaceous Seaway was more open to the south during the Niobrara time and allowed greater upwelling of more nutrients and thus more productivity. The Mowry did not benefit as much from upwelling as the Niobrara,” he continued. “If you go further afield, Eagle Ford oils benefitted even more from upwelling. The Monterey and Phosphoria had tremendous productivity because of upwelling.”

Aryl isoprenoids are another biomarker for something called photic zone euxinia. Euxinia is a lack of oxygen, which occurs because of green sulfur bacteria in the water where light can still reach. The bacteria need sunlight to live and survive by eating hydrogen sulfide, which makes the water anoxic and preserves organic material, he explained.

“Now we know we can get preservation of organic materials in places we never would have looked before, and that also guides our exploration efforts,” Curtis said.

In the Powder River and Denver basins, the Mowry oil family mostly occurs in the eastern part of the basin while the Niobrara is mostly in the center of the basin. With the oils, an operator needs to calibrate them by looking at the organic matter in the source rock to see if it makes geological sense.

“We can do that by looking at the thermal maturity and the quality of the organic matter in the source rock to make sure these are candidates for generating Mowry or Niobrara oil. If you have enough of a sample – a piece about the size of your thumb – you can extract from these source rocks and match the bitumen to the produced oil to get a comfortable feeling that you have determined where that oil came from,” he continued.

“It turns out oils that we have tied to the Mowry have mostly occurred in the Muddy formation, which is just below the Mowry source rock. The Mowry essentially expelled downward into the Muddy. On the other hand, the Niobrara is self-sourced within the different benches as well as from younger Upper Cretaceous reservoirs above the Niobrara,” he explained.

“The fact that we find oil outside the source rocks is not a concern for the resource plays. As it turns out particularly for liquids, expulsion efficiency is miserable. Most of the hydrocarbons generated by the organic matter are still present in these rocks. The source rocks are not being drained dry,” he emphasized. “So there are plenty of hydrocarbons left for the explorationists.”

The Niobrara and Mowry studies are “just a tiny bit of the integrated oil, gas, and rock studies that are commercially available. [GeoMark] is getting close to 20 companies buying data in the Niobrara and 16 to 17 companies in the Mowry.

“We don’t have anybody coming back to us and saying, ‘By golly, we used your data last week and now we have a 100-million-barrel field.’ We can’t make a direct correlation but we do have them buying the next study, which tells us it is of interest,” he answered to a question from E&P.

Contact the author, Scott Weeden, at sweeden@hartenergy.com.