Understanding Frac Fluid Distribution of an Individual Frac Stage from Chemical Tracer Flowback Data
- Wei Tian (ResMetrics) | Alex Darnley (ResMetrics) | Teddy Mohle (Contango Oil & Gas Company) | Kyle Johns (Contango Oil & Gas Company) | Chris Dempsey (ResMetrics)
- Document ID
- Society of Petroleum Engineers
- SPE Hydraulic Fracturing Technology Conference and Exhibition, 5-7 February, The Woodlands, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2019. Society of Petroleum Engineers
- 2.5.2 Fracturing Materials (Fluids, Proppant), 2.4 Hydraulic Fracturing, 5.6.5 Tracers, 5.6 Formation Evaluation & Management, 2 Well completion, 5 Reservoir Desciption & Dynamics
- Chemical Tracer, Frac Fluid Distribution, Fracture Diagnostics
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A data set is presented which involves pumping multiple, unique chemical tracers into a single ‘Wolfcamp B’ fracture stage. The goal of this tracer test is to shed light on the flowback characteristics of individually tagged fluid & sand segments by adding another layer of granularity to a typical tracer flowback report. The added intra-stage level detail can provide insights into fracture behavior when stimulating shale reservoirs by looking at individual fluid segment tracer recoveries. This data set could aid in the interpretation of:
Identifying fluid segments placed outside of the P-SRV (Propped Stimulated Reservoir Volume)
A total of 12 water phase tracers and 12 oil phase tracers were injected sequentially from "Pad" to "Flush". After pumping the pad stage, unique tracers were used to tag the "Proppant Laden Fluid" from the 0.2 ppa 100 mesh sand stage to the 2 ppa 40/70 mesh sand stage, before going to flush. The flush volume was not traced. Upon flowback, produced fluids were analyzed for the concentration of each tracer within the produced fluid samples. The first goal was to determine whether any traced fluid would be placed within "unpropped" SRV. The second goal was to determine the order of load fluid returns, to verify the "first-in, last-out" phenomenon, and to ascertain any degree of fluid mixing, which could be an indication of increased fracture complexity.
The results illustrate the average tracer concentration and arrival time of each traced fluid segment, which was then used to characterize the fracture stage. All tracers were detected in the produced fluid samples, indicating that no traced segment was placed outside of the propped fracture network. The results also indicate that significant tracer mixing occured within the fracture network, a potential indicator of fracture complexity. All individually traced segments flowed back simultaneously, albeit at varying tracer concentrations. The residence time calculation for each tracer showed that frac fluid injected into the later proppant segments generally flowed back faster than the earlier segments. No obvious piston-like displacement of frac fluid was observed from the tracer data.
|File Size||2 MB||Number of Pages||14|
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