Today, advanced seismic and reservoir characterization tools are being used increasingly in unconventional resource plays, even in shales.
That’s a little surprising.
Not long ago, operators approached unconventional plays with a basic geological understanding and application of technology for production.
All the learning curve was thought to be on the technology side – drilling techniques, use of horizontal wells, lateral length, fracture stimulation methods.
But consider this: Southwestern Energy Co. began drilling its highly successful Arkansas Fayetteville Shale play largely without 3-D seismic, and employed 3-D on only 20 percent of its Fayetteville wells in 2007.
By 2008 it expected to use 3-D seismic analysis on 75 percent of its Fayetteville wells.
And this year, more than 95 percent of the company’s wells will be drilled using data from a growing 3-D seismic database, Southwestern said.
AAPG Honorary Member Roger Slatt, a professor of petroleum geology and geophysics at the University of Oklahoma, is leading a research team in a reservoir characterization study of the Fort Worth Basin Barnett Shale.
Slatt has served as director of OU’s School of Geology and Geophysics, head of the Department of Geology and Geological Engineering at the Colorado School of Mines and director of the Petroleum Technology Transfer Council’s Rocky Mountain region.
The Barnett study pursues four objectives:
- To develop a log-, core- and seismic-based framework for regional mapping of stratigraphic and petrophysical units, with a sequence stratigraphic focus.
- To provide lithological/mineralogic input to determine and map petrophysical properties from well logs and seismic.
- To develop a systematic, integrated workflow for reservoir characterization of gas shales.
- To provide an educational program for students to develop expertise in gas shales for petroleum industry career opportunities.
A presentation about the research by Slatt and several co-authors was added to AAPG’s Search and Discoverydatabase earlier this year. The Barnett under study “is often considered to be homogeneous, undifferentiated black shale,” they noted.
“This is an important point,” Slatt said. “These are not just ‘black shales.’ There is quite a bit of variability.”
The Next Level
The study area covers about 100 square miles in the Newark East Field, the heart of the Barnett play.
“We’ve been doing a lot of work in the Barnett – and to a lesser extent in the Woodford (Shale),” Slatt said, “and we’ve come up with the workflow that pretty much covers the process.”
This approach begins with core description work, including thin sections and micropaleontology. Information is then correlated with wireline logs. Then high-resolution seismic and microseismic data are used for calibration.
“If you look at a typical seismic line through the Barnett, you can map the top of the Barnett and the bottom of the Barnett. A lot of companies do that, and then leave it at that,” Slatt noted.
“If you look into the Barnett, you can see that there are differences in reflectivity that are internal,” he said.
Application of seismic and other reservoir characterization tools has enabled the researchers to identify sequences within the shale.
“What we have found is that within these 10 rock types, they seem to be stacked in some kind of predictable fashion,” Slatt said.
Sequence identification and characterization can come from correlation through comparative mapping of related facies successions, rather than marker beds – an application of parasequencing to an unconventional resource play.
In this case, the stratigraphic framework was developed by analyzing the lithofacies stacking patterns, then defining parasequences.
“These Barnett rock types are arranged in parasequences,” Slatt explained. “You get changes in mineral characteristics.
“We’re doing seismic inversion now to improve our abilities in detecting these parasequences,” he added. “What we’re doing is going to the next level of characterization.”
Work so far has produced effective descriptions of the in-shale changes.
“Most of them are gradational,” Slatt said. “You might have a quartz mudstone and a calcareous mudstone at the ends. Then we might have phosphatic mudstones that are quite different.”
He said the study has recognized differences in organic content of the different facies – dolomitic facies or ash facies, for instance – in the Barnett play area.
Also, “we’ve been finding some excellent biomarkers. We can look at certain biomarkers and different ones occur in a rising sea level and in a falling sea level,” Slatt noted.
Plans call for the Barnett study area to be expanded. Research already shows areal differences across the Fort Worth Basin.
“One reason it’s important to go up another level of characterization is that your source areas change over time, probably due to tectonic changes. They’re not all continuous across the basin,” he said.
Operators are increasingly using 3-D seismic and microseismic in their resource plays. Microseismic typically gauges fracture response, and comprehensive reservoir rock studies will add another dimension to predictability.
“What we recognized from the microseismic is that when you look at microfractures, you see that the microfractures are stratigraphically confined. That implies to us there is some stratigraphic control,” Slatt said.
“What we’re trying to do now is to directly identify those microfracture zones that relate back to the stratigraphic zones,” he added.
Use of reservoir characterization and sequence stratigraphy tools in gas shales appears to be a coming thing, with advanced seismic results now being added in with core/log correlation studies and production data.
Devon Energy Co. of Oklahoma City funded the Barnett study and provided data. The company also supported an investigation of Oklahoma’s Woodford formation led by Slatt.
That OU-Devon-Schlumberger project cored 200 feet of Woodford Shale section behind an active quarry in southern Oklahoma.
Researchers found that macroscopic features visible in whole core appeared in image log data. When sufficient in proportion and thickness, the features also could be resolved on conventional logs.
Those features include phosphate and pyrite nodules, near-vertical healed fractures and pulses of silica-rich layers.
Distinctions stood out in distinguishing between the stratigraphic sections of Middle and Lower Woodford apparently present in the cored interval, the researchers said.
Larger scale features – for instance, layers rich in phospahtic nodules and lenses – were correlative over at least 600 feet along the quarry walls.
In both the Barnett and Woodford studies, results promise a better understanding of the shale and a clearer indication for placing laterals within the reservoir.
“It’s all aimed at ‘Where is the best place to put your horizontal wells?’ based on the stratigraphy,” Slatt noted.
In addition, the research has played an important role in introducing students to an emerging area of exploration and production.
“One of the keys to this project,” Slatt said, “is that we’re educating students in unconventional resource exploitation.”