Advances in directional drilling and reservoir stimulation techniques have dramatically increased gas production from wells drilled in shale reservoirs that were considered uneconomical not too long ago. In spite of many advances made on understanding the production behavior of this type of reservoirs, there are many unknowns that still do not have a proper answer. Particularly, it is difficult to predict productivity from cores, logs or DSTs or from early well production performance. Drainage volumes are uncertain and well spacing is based on trial and error methods.

The use of micro-seismic and production logs has helped in the fracture evaluation to determine the drainage volume and fracture inflow. Micro-seismic can provide useful information on the development of fracture symmetry, half-length, azimuth, width and height, and their dependence on the stimulation treatment parameters and reservoir characteristics. Additionally, these fracture geometries in conjunction with other measured or calculated parameters (rates, inflow models) can be used to better understand fracture modeling and production characteristics.

Reviews of production logs have indicated that only a percentage of the fractures are contributing to the production, however considering that this is a transient system, a snapshot measurement is not enough to understand the behavior of the fractures and their contribution over time. It is necessary to have continuous or permanent information from within the wellbore to establish which fractures are contributing and how much.

The near-wellbore temperature distribution yielded by distributed temperature sensing (DTS) or multi-point or array temperature sensing (ATS) can be used to determine the relative amount of fluids that each perforation interval contributes. If this information is combined with one or more pressure measurements and a real-time surface multiphase flow measurement in conjunction with an inflow model for each fractured interval, a production allocation could be calculated for each fracture. This approach is analogous to a traditional well allocation where a daily aggregated measurement at the production plant is back allocated to each well based on wellhead measurements like pressure, temperature and well performance. This paper will provide details on the above mentioned analogy and the use of these technologies to analyze the fracture behavior in horizontal wells in shale reservoirs.

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