An area of great interest to those researching flowback is the interaction of water and salt inside the shale reservoir. After a well is stimulated, the flowback fluids tend to show a rising concentration of salt that falls back to near zero over time.
The goal is to analyze this salt concentration curve to determine the complexity of a well’s fracture network. This is important since complex fractures are estimated to have a flowing surface area of 50 to 1,000 times greater than a simpler, or planar, fracture.
The applications for this area of study could be far reaching because nearly all North American shale plays were once covered by salty seas. As the water evaporated over the eons, the salt was left behind. In some shales, the salt is contained in formation water, but not always. So figuring out how exactly that salt ends up in the wellstream may explain how oil and gas move through the shale matrix, into the fracture network, and eventually the wellbore.
The University of Alberta (UA) researchers are using core samples from different Canadian shales to model the increased fracture area based on the dissolved salt content in the flowback fluid. So far, they have established three types of salt that may explain how it moves: loosely attached, moderately attached, and strongly attached.
“We are doing a lot of research on the source of salt and it’s really challenging,” said Hassan Dehghanpour, an assistant professor at UA. “But, if we know the source of the salt, then the question becomes how to upscale what we know from the lab observation to the field.”
If the salt is dissolved from the fractures, then it might be increasing permeability. However, researchers at the University of Houston (UH) believe as the injected water is produced back over time, more salt may leach out from the shale matrix and crystallize in pore throats, fractures, and even the spaces between the proppant, decreasing the permeability.
Hoagie Merry, a petroleum engineer who researched dissolved salt content in flowback fluids for his master’s thesis program at UH, believes if this dissolved salt theory can be proven by analyzing the flowback and production chemistry, producers may have cheaper options for restimulating a well.
“Instead of refracturing with proppant and everything else, we think they could try refracturing with fresh water, redissolving that salt in the main fracture and secondary fracture systems and perhaps even a little bit more salt in the formation, and obtain a larger dissolved stimulated rock volume and reactivate the salt that precipitated out, which was costing you permeability,” he said.
The other question that UH researchers are working on is whether a producer wants to see salt at all. “We think probably not,” Merry said. But in cases where it is simply unavoidable, producers may be able to use openhole logs to determine which parts of a field have the highest salt content and incorporate that information into their economic models. “There is much more cost at the surface in treating the water to knock the salt out and dispose of it,” he said.
In high-salt parts of the field, operators may also opt for initial fracturing jobs that use a greater amount of fresh water to dissolve as much salt as possible to increase the performance of the well. “If you got your lease there and you want to drill it out, I think it’s probably beneficial to know if it’s salty, how you’re going to deal with it,” Merry said.
For Further Reading
SPE 168598 Fracture Characterization Using Flowback Salt-Concentration Transient by A. Zolfaghari, H. Dehghanpour, E. Ghanbari, University of Alberta, et al.
SPE 175061 Model for a Shale Gas Formation with Salt-Sealed Natural Fractures by H. Merry, Sentinel Technology Solutions, C.A. Ehligh-Economides, University of Houston, and P. Wei, Sinopec Research Institute of Petroleum Engineering.
