Distributed Temperature Measurements Allow Fracture Diagnostics During Flowback
Authors: Carpenter Chris 
Published: June 2020

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195221, “Fracture Diagnostics Using Distributed Temperature Measurements During Stimulation-Fluid Flowback,” by Yilin Mao, SPE, and Mehdi Zeidouni, SPE, Louisiana State University, and Caroline Godefroy, Interpretive Software Products, et al., prepared for the 2019 SPE Oklahoma City Oil and Gas Symposium, Oklahoma City, 9-10 April. The paper has not been peer reviewed.
The significant temperature difference between the fractured and nonfractured regions during the stimulation-fluid flowback period can be useful for fracture diagnosis. Recent developments in downhole temperature-monitoring systems open new possibilities to detect these temperature variations to perform production-logging analyses. In the complete paper, the authors derive a novel analytical solution to model the temperature signal associated with the shut-in during flowback and production periods. The output of this work can contribute to production-logging, warmback, and wellbore-storage analyses to achieve successful fracture diagnostic.
Introduction
Information about individual fractures is critical in determining whether fracturing jobs have been successful or refracturing is required. Exploring new methods to evaluate fracture characteristics has been the focus of recent research activities. Triggered by field implementations and observations, research has been conducted to investigate temperature profiles during the early hydraulic fracturing and late production periods to characterize fractures.
Current research on the use of temperature data to evaluate hydraulic fractures and reservoirs focuses on developing forward numerical and semianalytical models to predict temperature profiles during fracturing and production. As a prelude to the production period, stimulation fluid flowback is often performed after hydraulic fracturing operations to remove the remaining fluid and loosen proppant from the wellbore. Because recording the flowback operation may be required already by regulations, the cost of collecting data from the flowback period is minimal. As a result, ongoing research on analyzing data from the flowback period has aimed to diagnose fracture design and efficiency, characterize key reservoir properties from the chemical composition of the flowback fluids, and predict long-term production. Such efforts are based on the critical timing of the flowback period - a transition between what happened during completion and what will happen during production. The potential temperature modeling on the flowback period proposed here shares the same insight. Shortly after hydraulic fracturing stimulation, the temperature in the fractured region is still lower than in the nonfractured region.
The objective of this work is to perform fracture diagnostics with the flowback temperature signal. The main objective is identifying inflow temperature from each of the fractures, critical as an input for production-logging-tool (PLT) analysis. Preliminary simulation studies found that the inflow temperature is identical to the surrounding fractured region temperature, which is masked by the heating effect introduced from wellbore fluid flow after the shut-in test (afterflow). Therefore, the authors propose analyzing this heating effect with analytical and numerical models, which are described in the complete paper. Once the heating effect is quantified, the inflow temperature for each fracture can be obtained.