Sensor Array Enables Accurate Profiling of Produced Fluids During Drillstem Tests

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This paper describes the use of a downhole temperature-sensor array during a commingled drillstem test (DST) to determine the density of produced fluids accurately. In a typical DST that uses only downhole pressure gauges, any fluid contacts between the pressure gauges would be missed and the produced-fluid density calculated would be erroneous. The complete paper demonstrates the importance of taking fluid properties into account when determining the zonal flow-rate contributions using the mass-enthalpy method.


Downhole temperature-sensor-array data provide accurate fluid contact depths during buildup periods of the DST that typically cannot be observed in pressure gradients. Determination of these fluid contacts permits the calculation of individual produced-fluid densities.

In a case study described in the complete paper, the deepest perforated zone produced a fluid with a higher density than that seen in shallower perforated intervals. The higher density of the produced brine caused the wellbore fluids to slug during the flow periods with a measurable response in pressure and temperature data. If this difference in the fluid properties is not taken into account, zonal-allocation flow rate will be in error because it relies on density and specific heat capacity. Qualitative assessment of the temperature-array data identified producing zones and clearly highlighted different fluid interfaces in detail that would remain hidden if the pressure gauges were relied upon solely.

High-Resolution Temperature Measurement During DST Operations

The deployment of the downhole temperature-sensor array during DSTs provides an in-depth look into reservoir characteristics that go beyond traditional downhole pressure-gauge measurements. The temperature sensors, contained within steel tubing and clamped to the outside of the tubing-conveyed perforating guns, cover the three perforated intervals in this case study.

Two temperature sensor arrays were run, each with a sensor spacing of 0.6 m and offset with an effective sensor spacing of 0.3 m. Throughout the DST, the readings from the temperature sensor arrays were recorded on downhole memory devices at 1-minute intervals.

The temperature measurement covered the entire perforated interval. High-resolution pressure gauges are placed above and below the perforated interval and above and below the tester valve. Using an acoustic communication system, real-time temperature and pressure data were available during the DST so that observations across the entire test could be made.

Zonal Allocation of Produced Reservoir Fluids From Mass-Enthalpy Balance

The mass-enthalpy method of calculating zonal contributions relies on intervals higher in the wellbore producing at a lower temperature than deeper producing intervals. The higher-temperature contributions from the deepest producing intervals will flow up the wellbore while losing some heat to the colder wellbore. The rate of cooling is dependent on the flow velocity. The shallower producing intervals contribute at a lower temperature than the mixture and will cool down the mixture. This method is detailed in the complete paper.

Pressure gradients between downhole pressure gauges are used typically to determine the density of the produced fluids in the wellbore. In a multizone interval, the accuracy of this method to determine not only the density of the fluids but also the fluid contacts themselves depends on use of an appropriate number of downhole pressure gauges. During the well test, however, it is common for gauges to be placed only above and below the total perforated interval and not between the perforated intervals. The accuracy of the fluid-density calculation using pressure gradients, therefore, is reduced.

Formation-Fluid Temperature

Temperature increases with depth in the Earth, and the rate of temperature increase is dependent on the type of formation and its thermal conductivity. Generally, the geothermal gradient can be found by recording the temperature of the well in the static region below the perforations; however, this is not applicable for temperature measurements taken during DSTs because the wellbore temperature has not reached thermal equilibrium with the formation. This is because the near-wellbore region has been cooled down by the circulation of fluids during drilling and is still in the process of thermal recovery during the DST.

Establishing the geothermal gradient, a process discussed in detail in the complete paper, is important for analysis of the distributed temperature across the reservoir and ensuring that the reservoir model is robust. In this particular case study, the bottomhole formation temperature was determined to be 248°F; therefore, the geothermal gradient was established at 0.108°F/m.

The drilling process greatly alters the temperature field of the formations surrounding the wellbore. In theory, the drilling process affects the temperature field of formations at very long radial distances, although there is a practical limit to this distance known as the radius of thermal influence. This cooling effect caused by the drilling process in this case study can be seen in the fact that approximately 15°F difference in the wellbore temperature exists compared with the geothermal gradient before perforating and flowing the well.

The temperature in the wellbore is measured before it has undergone full thermal recovery to the original geothermal formation temperature. This must be taken into account when computing zonal contributions and is an additional complexity when measuring temperature profiles during DSTs.

Using Distributed Temperature to Determine Wellbore-Fluid Properties

Determination of the wellbore-fluid contacts from the pressure gradients enables the density of the fluids to be calculated using simple fluid-­mechanics techniques. As mentioned previously, the pressure gauges are placed in the DST string above and below the perforated interval as well as above and below the tester valve. At the contact between two fluids in the wellbore, the pressure at the interface must be equal; otherwise, a static gradient would not exist. By using a normal hydrostatic pressure regime gradient (0.45 psi/ft), the fluid contacts in the reservoir can be determined. When the well is shut in for the main buildup period after the perforating and main flow period, this technique can be used to determine properties of the produced fluids. For two-phase flow, the calculation of the fluid densities from this method allows the mass flow rate to be attributed to each zone properly and also permits a more-­accurate determination of the Joule-Thomson coefficient. In this particular case, however, more than one fluid contact across the reservoir existed because the deeper perforations produced a higher-density fluid.

Using Temperature-Array Data To Determine Fluid Interface and Fluid Properties

After the flowing test periods, the well was shut in and the fluid column in the wellbore was static. The temperature profile during the buildup period indicated differing rates of cooling back to the geothermal gradient. This variation in the rate of temperature change is attributed to the fluids in the wellbore having different specific heat capacities, with the temperature data clearly showing the interface depth between the fluids. The temperature sensors below the fluid interface in the buildup periods exhibit a slower cooling rate than those above the fluid interface.

Without the temperature data, the fluid interfaces would not have been appreciable from the pressure gauge data alone because of the standard gauge configuration; as such, determination of the fluid properties would be subject to high uncertainty. Because of the slugging nature of the production from the deepest perforated zone, the depth of the interface between the produced oil and the produced water was different in each of the shut-in periods. Temperature profiles from the temperature-­array data can be used to obtain the well’s inflow profile—both the locations and the relative rates of the inflow.

Determination of Produced-Fluid Properties

The pressure gradient of the produced-oil phase is determined directly from the measured gradient between the pressure gauges below the tester valve and above the perforating guns. Extrapolating this gradient to the fluid-interface depth as measured by the temperature array between the denser liquid and the oil allows for the determination of the interface pressure. The pressure gradient of the completion fluid was extrapolated from the pressure gauge below the perforation guns to the fluid-interface level between the denser fluid and the completion fluid. With pressure and depth at each of the interface depths known, the density of the denser fluid could be calculated. This process was repeated for each of the three buildup periods to ensure that fluid properties were consistent. In this case study, the zonal-inflow contributions were determined from the mass-enthalpy method, taking into account the differences in the fluid density and specific heat capacity.


High-resolution temperature-array measurements were used to identify the presence of a denser fluid being produced from the deeper set of perforations. The identification of the denser fluid meant that the mass-enthalpy equation could be updated to reflect the differing inflow-fluid properties and therefore provide a more-accurate representation of zonal contributions.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29749, “Determining Produced-Fluid Properties for Accurate Production Profiling During a Drillstem Test Using Thermal-Imaging Technology,” by David Lavery and David Fyfe, Metrol, and Abu Rashid Hasan, SPE, Texas A&M University, prepared for the 2019 Offshore Technology Conference Brasil, Rio de Janeiro, 29–31 October. Copyright 2019 Offshore Technology Conference. Reproduced by permission.

Sensor Array Enables Accurate Profiling of Produced Fluids During Drillstem Tests

01 February 2020

Volume: 72 | Issue: 2

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