Visible Grains
Microseismic interpretation of fracturing requires judgment calls. It is common to detect seismic events thousands of feet from the wellbore the moment pumping begins to increase the pore pressure, said Mark Wilkinson, who worked for a microseismic company before becoming the vice president of unconventionals and geophysics at Ground Metrics, an EM-based company that worked on the Carbo test.
“No one interpreting that initial distant event would relate it to the fracture, but where do you draw the line?” he said, adding “more direct measure should create a better understanding.”
The company has provided surface monitoring services for Carbo, and is working on a research project for the US Department of Energy to track the flow of a high-contrast formulated fracturing fluid—highly conductive brine—during fracturing.
Imaging fluid or proppant requires a chemical makeup that creates a sharp contrast to the background rock. Because reservoirs are also somewhat conductive, a good target must be really conductive, on the order of 1,000 times to 10,000 times more than the surrounding rock, La Brecque said.
Multiple electric and magnetic reactions happen when an EM field stimulates a conductive proppant. Research teams are looking for which of those effects offers the best signal for imaging.
The sand and ceramic normally used for propping is a poor conductor, so the three groups are all looking for alternatives. A durable, cheap material is required because large quantities of conductive proppant are required to create a strong enough signal to be detected at a distance.
The only EM project that has disclosed what materials it is using is the AEC-backed group, which tested grains of steel shot and a conductive form of carbon known as Loresco coke breeze. The unconsolidated rocky soil allowed them to use hand tools to observe the fractures created.
Later this year, the coke will be used on the next test in a well that is 100 m deep. But in a producing well, a stronger material will be required to stand up to the pressures at greater depths, said Mohsen Ahmadian. Carbo and the UT fracturing consortium group did not disclose what materials they are using to create conductive proppant. When Palisch was asked, he referred to Carbo’s patent application, which covers a wide range of possibilities.
Sharma said the UT fracturing consortium plans to make proppant from a commonly available material that costs more than sand but less than the bauxite used to make ceramic grains. Lab tests indicate this unnamed substance is strong enough to ensure “good fracture conductivity even at high stresses,” he said.
Distant Sensing
The idea of searching for oil by identifying differences in electrical resistivity goes back to first use of the method for subsurface mapping by the Schlumberger brothers 100 years ago. “The electromagnetic method is one of the earliest forms of geophysics. It has been around forever,” Wilkinson said. What is new are the ways electromagnetic energy is injected into the reservoir and the receiver technology used to observe its impact.
In the Carbo test, power was sent down a cable to a point at the heel of a horizontal well where it was put in contact with the well casing, making the steel pipe a source of electric and magnetic fields that stimulated the specially prepared proppant.
Using casing as an antenna for EM has not been around long. It is used widely by Ground Metrics, which was hired to deploy 20 of its EM receivers for the Carbo test to gather data from the stimulated proppant. The image was created by comparing the difference between the data gathered during 30-minute periods before and after fracturing.
The new-generation receivers, developed with support from the US military, measure changes in the electrical potential in the ground. Wilkinson said they are more reliable than galvanic devices, whose readings fluctuate significantly, and the older receiver designs are more difficult to install and maintain.
The UT fracturing JIP’s technology program, which is funded by the US Department of Energy, is working on two approaches that work within the well.
One is a low-frequency induction logging tool for open hole completions, and the other is permanent contact electrodes that serve as EM transmitters and receivers for cased wells.
Its partner on the induction logging tool is Gearhart Companies, which is applying EM experience gained developing directional survey tools. The UT fracturing JIP is working with E-Spectrum Technologies for the hardware for cased holes, Sharma said.
The electrodes can cover an area that is “a few hundred feet,” he said. This installed series of coils for transmitting and receiving could also be used to measure other geological features, such as fractures, and how they change. The tool from Gearhart has undergone laboratory testing and Sharma said they are aiming for a field test in a shallow well this summer.
Long Term
Carbo has seen the power of a picture. While the fracturing business is in a deep funk, these projects are moving forward. The process draws on advances in a range of disciplines from material science to geophysics.
When Carbo began looking for a way to image where proppant goes, it sought help from a government research lab, Sandia National Laboratories, Palisch said.
It chose one of their suggestions, which coincided with work done by a Carbo researcher Lew Bartel. Since then, David Aldridge, a research geophysicist at Sandia National Laboratories, has advised Carbo on issues, such as how to interpret EM data over a long wellbore where it will be affected by the irregular and unpredictable geologic conditions.
One of the most difficult aspects of proppant imaging is developing the inversion methods used to isolate and image that needle of useful EM data, and remove the noise added by electric fields around the wellsite. While seismic is based on a different sort of signal— sound waves—both methods require sophisticated algorithms to turn huge amounts of data into a useful image.
“Seismic inversion has occupied geophysicists for the past 50 years,” Sharma said. “We are just starting out. Our work is just scratching the surface. We are at the beginning of this road.” The pace of onshore fracturing work requires quick, low-cost processing. A progress report filed late last year by the UT fracturing said that its “method used to solve the equations is computationally intensive and efforts are under way to speed up the simulations by an order of magnitude.”
For the AEC project, the processing side of things is a priority. “One of the deliverables is the best inversion software validated by physical evidence”, Ahmadian said.
To validate the code, the team carefully excavated the area fractured in its first test. “The site was shallow enough to excavate to test our prediction,” he said, adding they were happy to see, “our code was very good.” The next step will be a UT test well, where coring will be used to observe if the imaging matched the fractures found at a much deeper depth than its initial.test.
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