Energized fluids—with the success of hydraulic fracturing in the US shale-gas plays, why are more operating companies not using energized fluids to minimize the use of water, decrease the amount of proppant required, and (theoretically) enhance long-term productivity?
With the success of hydraulic fracturing in the US shale-gas plays, why are more operating companies not using energized fluids to minimize the use of water, decrease the amount of proppant required, and (theoretically) enhance long-term productivity? It appears that Canadians have been somewhat more receptive to the idea and are more willing to use energized fluids, with apparently positive results. Perhaps it is too early in the game to convince operators in the US to take another look at this technology with an open mind. Allow me to start a dialogue in this area.
The perception that using energized fluids is more expensive to achieve the same goal could be one hurdle keeping operators from using them. Nonetheless, let us take a step back and think of some of the more obvious, readily understood benefits: minimizing the use of water and decreasing the amount of proppant. Every operator knows the vast quantities of water required in hydraulic fracturing. This is a commodity that appears to be readily available, but it is not. And this problem will only be exacerbated with time. One of the insidious issues is that not all the water used during fracturing is recovered when flowing back the well, and whatever water is recovered cannot be used in subsequent fracturing stages. Hence, there are huge costs associated with water alone. Proppant, the nice, homogeneous sand grains that keep the fractures open and permeable, is also costly. Decreasing the amount required per stage is equivalent to more money in the operator’s pockets. When one realizes that many countries with enormous shale-gas plays do not have vast resources of readily available water, then the game changes. This may even result in an excellent public relations opportunity when the general public realizes that oil companies care about the environment and the precious resources.
For this issue of JPT, it was quite difficult to select three articles because there were so many excellent papers. I have attempted to narrow down the many papers to three that provide a broad perspective and the astute use of well-test data to be insightful to all readers. The interested reader will find many good articles on this subject in the OnePetro library.
OTC 25207 Innovative Positioning of Downhole Pressure Gauges Close to Perforations in HP/HT Slim Well During a Drillstem Test by AbdulHakim Al-Nahdi, Saudi Aramco, et al.
SPE 171686 Successful DST Methodology Adopted in Highly Deviated Deep, Sour, and HP/HT Exploratory Well: A Case Study by Abdulla Al-Ibrahim, Kuwait Oil Company, et al.
IPTC 16427 Mini-DST To Characterize Formation Deliverability in Unconventional Reservoirs by B. Kurtoglu, Marathon, et al.
Angel G. Guzmán-Garcia, SPE, is an independent energy consultant. He holds a PhD degree in chemical engineering from Tulane University. Guzmán-Garcia spent more than 23 years with ExxonMobil, where he held a variety of positions: conducting research on the response of resistivity tools in shaly sands; investigating nuclear-magnetic-resonance petrophysical applications; conducting and interpreting production logging; designing fluid-sampling collection and pressure/volume/temperature analyses; and designing, executing, and interpreting well tests in both siliciclastic and carbonate environments. He is an instructor in well testing, production logging, and petrophysics and is a member of the JPT Editorial Committee.