DEVELOPMENT OF FRACTURE DIAGNOSTIC METHODS FOR FLUID DISTRIBUTION BASED ON QUANTITATIVE INTERPRETATION OF DAS AND DTS

Abstract

Multistage hydraulic fracturing design on horizontal wells has significantly evolved with larger fluid volume, more fracturing stages, and tighter perforation cluster spacing to efficiently stimulate unconventional reservoirs. From the published field observations, the recent fracturing design results in complex fracture networks or swarm of fractures. Fracture treatment evaluation is extremely challenging in such a case, because of the large amount of variables in well completion and stimulation design. Combined measurements from different technologies can help in fracture diagnosis. Fluid distribution, either during fracture injection or during production, directly relates to the stimulation efficiency at the cluster level, and at the stage level. Since it is unlikely in the real world to distribute the injected fluid uniformly among all the clusters, we need diagnostic techniques to generate the flow profile along a lateral. Fiber optic measurements including Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) are currently used to diagnose downhole flow conditions. This technology allows us to qualitatively confirm the fluid flow profile and other issues occurring downhole during fracturing such as leakage through plugs. For optimizing a fracturing design, we also need to understand how the design parameters are correlated with the stimulation efficiency. In this study, we combine the two sets of models of DAS and DTS data interpretation for injected fluid volume distribution. DAS is interpreted based on an empirical correlation between fluid flow rates and frequency band energy from the acoustic signals. DTS is interpreted by performing temperature history match based thermal energy conservation. Because of the completely different physics behind the interpretations, the confirmation of the two interpretations provides confidence in fluid distribution.