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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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Measuring hydraulic conductivity of saturated soil (Ks) is one way to quantify soil hydraulic properties. However, this technique is very time consuming for both in situ and laboratory measurements, and often one is limited to measuring only one sample at a given time. Automation of hydraulic measurements has been suggested, but this has not been done for laboratory Ks measurements. Thus, we propose to use pressure transducers to measure Ks in multiple soil cores with a falling head permeameter. To accomplish this, an automated falling head permeameter was developed by attaching pressure transducers to falling head permeameters to measure Ks of soil cores in the laboratory and a datalogger was used to record the readings. To test this method, 64 soil core samples were taken from two locations, 30 from a sandy soil, 23 from a silt loam soil, and 11 from a silty clay loam soil. The automated unit allows for six samples to be processed with minimal human oversight compared with only one sample being read manually (conventional method), requiring frequent observations during a period often >30 min. When values obtained using the automated method were compared with values obtained for the same cores using the manual technique, there was no statistical difference at the 95% level.