Well-defined Spacing and Sequencing
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August 06, 2014
The shale gas boom has become a game changer in our nation’s energy landscape. Dr. Mukul Sharma has been conducting research on the topic for more than 10 years – far before hydraulic fracturing became a household name.
Sharma, in his research lab, analyzing a piece of shale
He is addressing some of the largest hydraulic fracturing challenges, including how to increase the estimated ultimate recovery.
Sharma and Ph.D. student, Ripu Manchanda, are working to best understand the complex network of fractures.
“We are looking at optimizing the well and fracture spacing as well as the sequencing – all three variables are linked together,” said Manchanda. “It’s a three-pronged approach and we want to define how they impact one another in the subsurface.”
Over the past few years, zipper fracturing (frac), has become an important industry term associated with hydraulic fracturing as it improves well performance and reduces the rig time. The two-well zipper frac technique fractures adjacent wells in sequence, enabling one well to hold fracture pressure while the adjacent well is being fractured. There was not a lot of science behind why this process works, so Sharma and his team used field data from the Eagle Ford shale and other plays to develop an accurate model for the process.
“Industry had a vague explanation for why zipper fracturing works, but we showed that it is the time between adjacent fractures in a well that controls things,” said Sharma. “If you give yourself the most amount of time between one fracture and the next fracture in the same well there is a tremendous advantage. The stress shadow is time dependent and giving it more time between fractures causes the stress shadow to become much less important.”
Manchanda is discovering a way to create a general model for better understanding zipper fracs that is applicable in all shale plays.
“If you can characterize the well by understanding the fluids and mechanical properties of the rock, then you can put those parameters into the model,” said Manchanda. “3D simulation is important to view all wells; I want to model the processes, so people can simulate multiple fractures in multiple wells. We are defining the best option to optimize recovery.”
Sharma and his team’s goals are to help push the estimated ultimate recovery for these wells up by 10 to 30 percent by optimizing the fracture spacing and well spacing.
“I think what people are finding is if you put wells closer and closer you tend to get reasonably good production from infill wells,” said Sharma. “The problem is that if you fracture these infill wells the fractures run into the old fractures, because they tend to go towards the part of the reservoir that has been depleted. You want fractures to go into a fresh part of the reservoir that has high pressure. Unfortunately, that’s not where the fractures want to go.”
Discovering a solution to this issue and providing a modeling tool that will help operators design fracture treatments, select well spacing and fracture spacing is at the top of Sharma’s list.
Sharma’s group is also in the process of building a downhole tool that is specifically designed for improving recovery in tight rocks.“This tool will be of great interest to a lot of operators in the Bakken and maybe the Eagle Ford - any oil reservoir that is tight is a perfect fit,” said Sharma.
The development of this tool is so important because primary oil recovery factors are about six percent, according to Sharma. It is difficult to conduct improved oil recovery in extremely tight rocks by injecting into one well and producing from another. The oil migrates between wells at an incredibly slow rate, or it simply flows along fractures. “What we are proposing is that you inject and produce from the same well at select locations to achieve first oil faster and that’s never been possible before.”
