The surging oil and gas production from shale plays in the United States is essentially mind-boggling – there’s even ongoing chatter about exporting some of the swelling supplies.
In stark contrast, shale E&P activity in Europe has yet to really take off.
This contrast has prompted some to press the research button to implement a study to compare the North American and European shale gas and oil resource systems.
“The activity is dictated by two things,” said AAPG member John Curtis, professor emeritus at Colorado School of Mines and director of the Potential Gas Agency there. “The rocks and the organic matter and the geologic history are one, and the other is regulatory and infrastructure.
“We’re upstream, so we could take a look at what the geology and geochemistry had to say,” Curtis said. “This was to see the utility of these data – especially the oil data, because with oils you know the reservoirs they came from and you can type back to the source rocks and then get a feeling for the entire petroleum system.
“We did this in a way that we could look at the oils in a number of basins and see what characteristics they had in common,” he said. “We needed the depositional environment, thickness, organic content and such to pick that out.
“We were able in a broad sense to map these fairways.”
The study, which Curtis undertook in conjunction with GeoMark Research in Houston, employed a sizeable oil database covering North America and all except eastern Europe to compare and contrast the potential of shale gas and shale oil.
European rocks/locales included in the study are:
- Kimmeridge clay – North Sea.
- Alum shale – Baltic.
- Posidonia shales – Poland, Hungary and Russia.
- Toarcian shale – Paris Basin.
- Bazhenov shale – West Siberia.
“We compared the European basins to the Barnett shale, the Eagle Ford and a whole series of oils in the Rocky Mountains,” Curtis said. “In comparing the North American oils to the European oils, we were able to derive the depositional environment, which was deepwater in many cases.
In fact, the “best thing we ended up identifying,” Curtis said, was:
- The deepwater marine source rocks (type II kerogen).
- The correct level of thermal maturity to have converted organic matter to hydrocarbons.
- The correct mineralogy within the reservoir rocks that would be amenable to stimulation.
The Best Thing Is…
Curtis emphasized that a model for shale gas and shale oil producibility requires ample shale thickness, organic content (ideally hydrogen-rich) and a sufficient level of thermal maturity to generate economic gas or oil volumes. Ideally, the rock matrix is silica-rich and low in clay in order to be brittle enough to enhance stimulation treatment effectiveness.
“Probably the best thing about our study is if you get new oils and have the data, you can plug things in and then see where the new data fit,” Curtis said.
There are no plans to publish a report about the project, but Curtis will fill you in on the details during his talk at the upcoming AAPG Annual Convention and Exhibition in Pittsburgh.
He emphasized that it will be a “data-rich presentation.”