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In this paper, the use of microseismic data for calibration and modification of wellbore temperature models will be introduced. Moreover, fracturing fluid distribution obtained using the modified temperature numerical model is coupled with the microseismic field data for several Eagle Ford shale wells to improve hydraulic fracture stimulation characterization. By measuring the temperature change along the wellbore, distributed temperature sensing (DTS) data may provide relative fluid distribution. This information may be used to assess the simple geometry of the hydraulic fractures, the fracture initiation points along the wellbore, wellbore integrity issues, and the effectiveness of isolation tools. With recently published wellbore temperature models, quantitative information about which zones receive the stimulation fluid can be numerically solved. However, DTS measurements and fluid distributions calculated using DTS data are restricted to the wellbore and near wellbore environment. For far field diagnostics of hydraulic fracturing stimulation other measurements are needed, specifically microseismic. By combining these two measurements, a new workflow is created which incorporates both the far field and wellbore measurements to characterize hydraulic fractures, both real-time and after the stimulation job. This workflow is especially useful in reservoirs that are naturally fractured or in wellbores were stress shadowing effects are significant, such as multistage fracturing multiple wells that are in close proximity to each other. In these scenarios the path that the fluid travels may be complex, even in the near wellbore environment. Due to this complexity, fluid distributed calculations based on DTS data may provide misleading results. Using information gained from microseismic, the wellbore temperature models may be modified to increase the reliability of the numerically calculated fluid distributions. The purpose of this paper is to propose how microseismic data may be used to modify the wellbore temperature models, and how stimulation fluid placement determined from the modified models may then be coupled with the microseismic to improve hydraulic fracture stimulation characterization.
Abstract The influence of hydraulic fractures during production is to alter the wellbore/sandface temperature changes by reducing the magnitude of the Joule-Thomson expansion effect. Compared to an unfraced completion in which the flow path of the reservoir fluids is purely radial, the presence of hydraulic fractures lengthens the flow path the reservoir fluids must take by creating a linear flow geometry. For a given drawdown, therefore, the local pressure gradients are lower in a hydraulically fractured completion compared to a non-hydraulically fractured completion. Through dimensionless analysis it will be shown that the Joule-Thomson effect is proportional to the local pressure gradient squared which implies a reduction in the Joule-Thomson effect for a hydraulically fractured completion compared to a non-hydraulically fractured completion. Simulations from a thermal reservoir/wellbore model will be presented comparing the thermal responses between hydraulically fractured and non-hydraulically fractured completions. It will be shown that the presence of hydraulic fractures can reduce the wellbore/sandface temperature changes by much as 85% compared to a non-hydraulically fractured completion. Additionally it will be shown that measurement of sandface and wellbore temperatures during production can provide information to determine which intervals have been successfully hydraulically fractured, and to a lesser extent a qualitative assessment of hydraulic fracture efficiency.
It would be exceedingly hard to find anyone with more experience extracting data from a fractured reservoir than Kevin Raterman. After nearly a decade as co-leader of ConocoPhillip's one-a-kind test site in the Eagle Ford, Raterman, a reservoir engineering advisor at the company, has had the opportunity to use just about every sort of diagnostic test. He was the lead writer on the latest technical paper (URTeC 263) about the test site that studied "core, image logs, proppant tracer, distributed temperature sensing, distributed acoustic sensing, and pressure, which shows that not all hydraulic fractures are created equal." Among those, the measurements from an array of downhole pressure gauges loomed largest. Raterman's advice to those analyzing fractured reservoirs is to install more downhole pressure gauges to identify where fractures are draining the rock and where they are not. Those carefully placed sensors observed large pressure differences at locations as close as 45 ft apart. "The more spatial pressure data you have, the better off you are," he said. Pressure gauges are one of the oldest tools for reservoir analysis, and one of the more affordable.
Monitoring hydraulic fracturing is important for optimizing well-completion and well-spacing. Monitoring efforts, so far, are limited to observing micro-seismic activity, shear-wave shadowing and velocity changes from a neighboring monitoring well. The advent of Distributed Acoustic Sensing (DAS) has allowed us to monitor changes from the treatment well itself. We describe a novel active-source seismic experiment with DAS in a treatment well and discuss time-lapse changes due to hydraulic fracturing. We observe amplification and attenuation of direct P-waves above and below the plug for each stage, respectively. These strong time-lapse changes appear to be long-lived, at least over a period of 10 days. The time-lapse phase changes are small and hard to interpret. We believe that the amplification in the stimulated zone is related to formation changes and the attenuation is probably related to fiber coupling changes. Though the current geometry is not ideal, DAS is promising for hydraulic fracture monitoring.
Abstract Cross-well communication data during a fracturing treatment can provide important insight into fracture geometry development and the interaction of fractures between adjacent wells. Additionally, these data potentially assist in measuring the effect that diverter technology can have on limiting the length of fractures and increasing near-wellbore (NWB) complexity. Existing diagnostic tools for assessing well interference during fracturing include pressure monitoring, microseismic imaging, oil-soluble tracers, water-soluble tracers, radioactive tracers, tiltmeters, and permanently installed fiber-optic distributed temperature and acoustic sensors. All of these tools are generally applicable to infer the absence or presence of well interference during fracturing and can be used either exclusively or holistically to this end. This paper discusses using coiled tubing (CT) deployed fiber-optic distributed temperature and acoustic sensors as an additional tool for well interference testing during fracturing and includes a case study wherein this technology was applied to evaluate the effect of particulate diverters on fracture network growth. Also, an operational risk of CT burial in the observation well was successfully mitigated using a detailed risk and contingency plan. Results of the interference observed are shown, combining the different diagnostics. Introduction Diagnostics are important for understanding hydraulic fracturing. Although accurately constrained earth models can make reasonable predictions about hydraulic fracture behavior, actual measurements are necessary to validate predictions, calibrate models, and ultimately provide concrete data to make decisions about stimulation and well design. In particular, measuring fracture length is important for planning well spacing and predicting drainage patterns. In North American unconventional resource plays, a significant amount of attention has been given to continued development of existing acreage with infill drilling and down spacing, which has given rise to the phenomenon of well bashing. Well bashing occurs when hydraulic fractures from child wells (infill or down spaced wells) interact with a parent wellbore (the first development well) in the same area. The effect of well bashing on production is generally unpredictable but anecdotally appears to decrease the production of a parent well more often than increasing it. However, cases of both types have been cited previously (Craig et al. 2012). This phenomenon has also been studied using reservoir and fracture simulators (Siddiqui et al. 2016).