Real-time monitoring of hydraulic fracturing using fiber optic distributed temperature sensing (DTS) is starting to be used to estimate fracture initiation depth, vertical coverage and number of generated fractures, effects of diverting agents, and undesired flow behind casing. DTS monitoring of flowback and production can also help to assess the effectiveness of the stimulation treatment. To successfully achieve the monitoring objectives, aspects such as fiber deployment, fiber integrity at high injection rates, location and thermal coupling of fiber with respect to flow path, frequency of data acquisition and resolution, and real-time visualization and modeling need to be carefully considered. This paper presents experiences in the analysis of transient DTS data acquired during high-rate, multi-stage hydraulic fracturing in vertical, deviated, and horizontal oil and gas wells. The location of fiber, conveyed with coiled tubing inside the flow path or cemented behind casing, has a major impact in the temperature response, depending of the thermal conductivity between the fiber cable and the injected fluid path. When the fiber is hung inside casing, the fluid distribution can be challenging, especially if the deepest fluid leak is closer to the bottom of the treated interval, because the temperature along the fiber very quickly becomes equal to the fluid temperature with a minimum gradient straight-line pattern due to high fluid rate and velocity. To overcome this condition the use of induced hot/cold thermal tracers together with temperature modeling has been introduced, allowing the calculation of fluid rate distribution along the perforated intervals. Where the fiber is cemented behind casing, well defined patterns, based on the temperature value, can be recognized to discriminate between flow inside and behind casing, allowing out-of-zone fracture assessment. The thermal coupling of the fracturing fluid inside the casing and the fiber can be very weak at certain levels where small gas "insulation" pockets occur around the fiber, keeping the fiber temperature closer to the geothermal than fluid temperature. At clamp depths or well cemented zones, fiber temperature is much closer to fluid temperature, because the thermal coupling is strong at these levels. When the fracturing fluid flows behind casing, due to bad cement isolation, reaches the fiber cable, the temperature becomes essentially equal to fluid temperature. The advantages and limitations of both cases are discussed based on the type of well, length of gross pay, fracture design, treatment rate, and type of fluids.

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Summary In matrix treatments, placement of the injected fluids is essential for success. Over the years, several diversion and placement techniques have been applied to obtain a desired fluid distribution. Real-time evaluation of a treatment was limited to observing injection pressures or bottomhole pressures. These measured pressures provided information on the diversion process. The application of distributed-temperature sensing (DTS) during matrix treatments to monitor the temperature profiles along the wellbore in real time is a recent method to obtain a qualitative indication of the fluid distribution. In this paper, we discuss if DTS can also be used to quantify the fluid distribution during a matrix treatment. For the real-time quantification of the fluid distribution during a matrix treatment from temperature surveys, both real-time readouts of the temperature surveys and an accurate real-time model are needed. With DTS, the real-time readout is a feasible technique developed to present and evaluate the temperature surveys in real time. Further, a coupled wellbore and near-wellbore thermal model is available that runs in real time. This paper describes these techniques, models, and validations using several case histories. In addition, an analysis of matrix treatments using DTS temperature surveys, where available, are presented. The models are used in the analysis to obtain calculated fluid flow distribution. We discuss how this methodology can be applied in real time and what benefits quantification of fluid flow distribution offers. Further, we describe what other benefits can be obtained from real-time temperature profiles during stimulation treatments.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDistributed temperature sensing (DTS) coupled with a temperature-pressure simulator has been used successfully to determine flow profiles from multilayered commingled reservoirs in production gas wells. This technology has enabled quantitative individual-layer contributions to gas flow rates and main water entries to be determined, which in turn, has helped engineers to evaluate production conditions, track individual layer recovery, identify problem zones, and plan remedial actions.DTS technology uses fiber-optic cables to measure continuous temperature profiles along the entire wellbore without any cable movement.The real cases presented here include producing gas wells ranging from very low-permeability, hydraulically fractured tight reservoirs to high permeability sands with production rates from one (1) to tens of MMscf/d and over 50 layers per well at depths between 7,000 to 15,000 ft.The analyses have shown that some of the key parameters required to obtain representative flow profiles using DTS can be extracted from the flowing and shut-in DTS transient profiles.Those parameters, which are generally not available in conventional temperature logs, include: (i) geothermal profile; (ii) wellbore and near-wellbore Joule-Thomson effects, and (iii), thermal properties of fluids and formation. Nonproducing, thick zones are particularly useful when calibrating partial flow rates and verifying fluid and formation properties.The flow-profiling model was built around an analyticalnumerical, pressure-temperature simulator that predicts wellbore temperature profiles as a response to individual layer flow rates and sandface fluid-entry temperatures. An interactive error-minimizing technique was used to match the simulated temperatures with the actual DTS profiles. This paper also presents comparisons between the DTSderived flow profiles and the traditional production logging tool (PLT) profiles as well as the value DTS can provide for multilayered gas-reservoir monitoring.

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