DENVER—It wasn’t that long ago when oil prices were a lot more than $50 per barrel and companies felt great about using field crews to gather data. So now that the price has fallen, is there anything the industry can do with that already-collected data, which doesn’t require the expensive task of sending people and equipment out to the field?
More specifically, are there ways to use that data to optimize well production? And now that drilling has slowed and asset teams have more time on their hands, what else can they do with the data until there is more money for more data collection crews and rigs in the field?
At the 3-D Seismic Symposium, sponsored by The Rocky Mountain Association of Geologists (RMAG, Ross Peebles, CEO of Global Geophysical Services, said that 3-D and ambient seismic records have the potential to be standard tools for asset or field development activities.
“Using full three-dimensional data volumes can do wonders for practical drilling, completion and production decision-making,” he said. “But, they must be fast, actionable and in affordable chunks or modules.”
Peebles shared well data collected during a hydraulic fracturing operation that showed the location of fractures and the production amount from fracturing. He said that by installing ambient receivers to monitor fracturing and the well’s production , people can eventually get a better idea of which fractures worked best and provide the greatest amount of production.
“To set up an ambient receiver array and leave it for 10 days in the field is about 10 percent of the cost of the drill and complete at a pad,” he said.
He added that if the data is collected and modules are worked up, the data output is “twice as fast and then each of those modules are done; and you can be using the data now instead of months from now. The data can also help engineers spot the next well and reduce performance risks and cut costs.”
Understanding Stage Fracturing
A data gathering project in Wattenberg Field undertaken by Noble Energy Inc. (NYSE: NBL), Anadarko Petroleum Corp. (NYSE: APC) and Thomas Davis of the Colorado School of Mines, sought to find correlations between fluid and proppant injection and well production to better understand what occurs during stage fracturing. The study tried to integrate geophysics, geology, geomechanics, petrophysics and petroleum engineering.
In this 11-well (Niobrara and Codell) project, pressure curves were monitored during fracturing to understand what makes one well produce better than another.
“Geological factors were the most important thing for well location, stage location and spacing,” said Travis Pitcher, an exploration geophysicist for Noble Energy. “Through this study we found little correlation exists between completions parameters [fluid and proppant injection] and production, or between instantaneous shut-in pressure [ISIP] and fracture network complexity. The largest control on production variability in the study area appears to be geology, both at the seismic- and sub-seismic scale.”
Pitcher told the audience that “stress differences within the study area exist due to complex geologic structures that are largely controlled by faults. These features control pressure and stress distribution throughout the reservoir and are considered to be the main driving factors for production variability across the study area.”
Pitcher explained that faults in the reservoir create compartments that influence fracturing and that dense natural fractures “may be both mechanically and hydraulically active without placement of proppant.”
“Fluid and proppant injection volumes had little incremental effect on production when they were not ‘tailored’ to geology and stress conditions,” he said.
Predicting Reservoir Properties
Jeff Zawila, a senior geophysicist at SM Energy Co. (NYSE: SM) discussed a study conducted in Wyoming’s southern Power River Basin where an interdisciplinary approach to predicting the reservoir properties of tight unconventional sandstone was used. The study focused on horizontal drilling that targeted Turner/Wall Creek, Parkman, Sussex and Shannon.
Zawila presented an integrated multidisciplinary approach of correlating core facies to petrophysical wireline facies to seismic facies. In his study, the seismic facies and reservoir rock properties were calibrated to wireline logs and core data and were mapped from 3-D seismic inversion volumes.
“The maps provided a better understanding of reservoir characteristics, namely their spatial distribution, geometry and internal architecture,” he said.
In the first step, they identified 12 distinct lithofacies for wireline logs. The facies were correlated to acoustic/elastic parameters and “upscaled” to generate seismic facies. The second step transformed the 3-D seismic data to reservoir rock property volumes by geostatistical inversion.
According to Zawila, this approach “provided a predictive understanding of the complex unconventional sandstone and enabled ‘high-grading’ of areas for efficient development.”
In older developed areas, reprocessed high-resolution 3-D seismic data can be used to find thicker and more productive reservoir fairways to reduce drilling and completion risks in complex distributed reservoirs.
Tony Lupo, chief geophysicist at SM Energy, presented a case study conducted in the Cleveland Formation, which is a thin, tight-oil objective where drilling began in the 1920s along the Nemaha Ridge in north-central Oklahoma and Kansas.
“Using current 3-D seismic technology and multiattribute analysis can produce detailed sequence stratigraphic correlations to exploit a mature area in a repeatable fashion,” he said.
“Smaller operators with the technology and software can now be competitive in areas like this.
“The trickle-down of technology--technology developed during the recent resource play boom--can now show resources that have basically been under-exploited but still remain in abundance.”
Larry Prado can be reached at [email protected].