Features of distributed temperature sensor data analysis

<ns0:p>This paper presents an innovative modeling of continuous fiber-optic measurements to improve the dynamic characterization of injection wells during the early stages of carbon capture and storage (CCS) projects. The approach uses distributed temperature sensing (DTS) data collected along the well profile to map the thermal behavior in real time during three key phases: before injection begins, during the initial regime when carbon dioxide (CO2) displaces the brine in the tubing and fills the borehole, and during full stable operation. This physics-based methodology provides fluid mapping based on DTS, as well as a comprehensive description of the well thermal performance, essential for understanding and optimizing CO2 injection. The results obtained during CO2 injection into a depleted natural gas reservoir demonstrate the present method. The injection well completion is equipped with permanent fiber-optic cables for continuous DTS monitoring down to the production packer. While standard DTS can be used to monitor the well thermal performance during steady-state operations, other factors are essential for accurately monitoring the distributed temperature profile during transient operations. This study begins with an analysis of brine displacement from the tubing into the borehole during well commissioning. The dynamic behavior of CO2 during these operations led to thermal effects along the well tubing, which were addressed through an innovative analysis of DTS data. A reprocessing of the space-time temperature measurements was implemented to distinguish between the downward movement of gas and liquid within the tubing. This made it possible to locate the real-time position of the contact between CO2 and brine in the tubing, thanks to their different physical properties. DTS measurements and reprocessing outputs were successfully used to calibrate a physics-based well simulation model that describes fluid dynamics and thermodynamics, involving complex well geometries and multiphase flow conditions. Thus, the DTS-calibrated physics-based simulation model provided insight into the well’s thermal evolution and allowed for the real-time computation of important physical properties, such as the density, phase, and pressure profiles of CO2. The presented methodology provides strong dynamic characterization of CO2 injection wells from the beginning of a CO2 transportation and storage (T&amp;S) project. The resulting calibrated wellbore models are essential for CO2 injection optimization, flow assurance, and risk management. While there are several approaches to maximize information from permanent DTS data, quantitatively using temperature evolution for dynamic modeling is a novel technology that can shed light on the early and uncertain stages of CO2 T&amp;S projects.</ns0:p>

Mapping the microseismic activity during a hydraulic treatment is widely used to determine the geometry of the stimulated fracture network. Microseismic maps provide reliable information on the development of fracture symmetry, half-length, azimuth, width and height, and their dependence on the treatment parameters and reservoir characteristics. Beyond that, these fracture geometries are used to better understand fracture modeling and even production characteristics. Fiber-optic-based distributed temperature sensing (DTS) arrays provide almost immediate updates of the near-wellbore temperature distribution in approximately one-meter intervals. In injection treatments, the near-wellbore temperature distribution can be used to determine isolation effectiveness, the relative amount of fluid each perforation cluster takes, fracture initiation points, and effective fluid diversion. In production analysis, DTS measurements can quantify production rates from each perforation interval, crossflow rates while shut-in, and fluid types recovered from each perforation interval. The detailed near-wellbore results available through DTS coupled with the far-field geometry acquired through microseismic mapping provide an accurate picture of the completion effectiveness. Microseismic mapping results often show adequate resolution over a large area but lack the fine resolution that would allow it to identify near-wellbore effects in the meter range. When modeling and interpreting the treatment geometry obtained by the microseismic-event distribution, it is important to include the correct near-wellbore effects, which are readily accessible through DTS measurements. Combining the two diagnostic tools is valuable for real-time decision making, post-treatment analysis, and production analysis to assess the completion effectiveness. Incorrect assumptions about perforation breakdown, fracture-initiation points, interval isolation, or limited-entry effectiveness can lead to misinterpretations of the microseismic results. Using both diagnostic tools provides firm answers to the overall completion effectiveness. This paper focuses on three distinct aspects of combining the analysis of microseismic mapping and DTS. The first is the real-time aspect, wherein real-time decisions and adjustments are made during the fracture treatment with the objective of manipulating the results towards the desired outcome. The second is using both tools to perform more accurate postfracture analysis, including calibrated fracture modeling, entry effectiveness, correct interval spacing, and stimulated reservoir volume (SRV) analysis. The third area covered is combining these diagnostic tools with a production analysis, which is acquired through analysis of the temperature data.

Operators including Aera Energy LLC are evaluating distributed temperature sensing (DTS) systems as an alternative to production logging tools (PLT) and radioactive tracer surveys (RTS) for the determination of zonal allocation factors. If DTS data can be interpreted to provide wellbore velocities, zonal allocation can be determined without well entry and practically in real-time. In comparison to PLT and RTS, DTS could provide zonal allocation at a higher measurement frequency, lower cost, and lower risk to personnel, environment, and the well asset. In wells where casing deformation precludes wireline operations, DTS may be the only viable alternative. The purpose of this work is to investigate whether water injection zonal allocation can be derived from DTS data acquired in thermal tracer injection tests within an uncertainty comparable to RTS. Three waterflood injection wells with RTS and DTS data in Aera Energy"s Belridge field in California are analyzed. The zonal allocation factors derived from the DTS are shown to agree within uncertainty with the RTS-based results. The DTS for two of the wells is interpreted through history matching with an OLGA thermal-fluid model. The DTS for a third well is interpreted using the Temperature Inflection Point (TIP) thermal tracer method proposed in this work. The TIP method is a simpler alternative to history matching and was shown to be theoretically valid for wells with negligible heat transfer at the walls over the duration of the injection test. In this regard the TIP method is less restrictive than the Slopes method, which is currently used in industry but theoretically requires negligible heat transfer at the walls and within the fluid. The TIP method is also shown to be more consistent with the field data of this study. The paper concludes with guidelines on the design and implementation of thermal injection tests and TIP analysis. The most significant practical limitation of the TIP method is its sensitivity to noise in the data, motivating DTS acquisition at the maximum practical resolution, data smoothing, and averaging over multiple test realizations.

Designs and preliminary results from a multi-year project for simultaneous Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) executed across multiple wells on a Steam-Assisted Gravity Drainage (SAGD) field in Canada is presented. Primary objectives of the project were to demonstrate prototypical execution of DAS and DTS data collection on a standard SAGD pad setup and to characterize inflow across the production zone. Challenges and learnings from this technically demanding project are explored alongside a discussion on the improving viability of continuous acoustic monitoring to augment temperature sensing commonly utilized in SAGD instrumentation design. The DTS technique employs a combination of an optoelectronics topside instrument and a downhole sensing fiber to produce a distributed temperature profile of the fiber string. The topside instrument comprises a laser light source, a fast optical detector and a combination of electrical and optical circuits to control light pulsing, and the detection and measurements of Raman backscattered light containing encoded temperature information about the temperature profile. The sensing fiber type is selected based on suitability with the topside instrument and the expected maximum operating temperature of its intended sensing environment. While DTS is compatible with both single-mode (SM) and multi-mode (MM) fiber type, MM graded-index fibers are often selected for SAGD environment due to its larger optical core size. Using a MM fiber allows for increased capture of the backscatter Raman light, a much weaker light signal than the laser light launched into the optical fiber. Temperature dependent Raman signals are extracted from the returned light and by applying the Optical Time Domain Reflectometry (OTDR) technique, which produces a temperature trace consisting of temperature magnitude matched to each unit distance along the sensing fiber. The temperature trace can vary in its spatial resolution subject to the topside instrument configuration with typical resolving resolution between 0.5 – 1.5 meters. Other general DTS sensing techniques are described in the literature (for example, Hartog (2017)) but are not described here. Some of the earliest uses of DTS in thermal enhanced oil recovery (EOR) was to monitor steam breakthrough and pump vapor locking in California's steam flood as reported by Carnahan (1999). Since then, advancement in specialty fiber optics suitable for thermal environment upwards to 300°C has enabled mainstream adoption within SAGD. Uses of DTS data has expanded to include, but not limited to, monitoring of well and steam chamber conformance, tubing and casing integrity, gas ingression and water coning. DAS is an optical interferometry technique employing an optoelectronics topside instrument and a downhole sensing fiber to detect minute changes in fiber length at each location along the fiber string. The instrument is sensitive at the pico-strain (ρε) level with a spatial resolution equal to a configurable distance referred to as the gauge length. The term "acoustic" in Distributed Acoustic Sensing broadly designates any mechanical perturbation able to alter the local state of strain anywhere along the optical fiber, be it from dynamic pressure changes, or dynamic strain (e.g. vibration). While DAS is compatible with both SM and MM fiber type, deployment alongside SM fiber types have been traditionally preferred as the laser light coherence is better preserved throughout its round-trip propagation compared to MM fiber. However, DAS with MM fiber can still be used for typical fiber lengths in SAGD wells without significant penalty in signal quality as shown in literatures (MacPhail (2016), Burke (2022). This cross-compatibility with MM fiber allows collection of DAS on existing DTS fibers deployments without further intervention. Prior to DAS adoption in oil and gas, it was predominantly deployed in defense and security application to perform parameter monitoring and ground disturbance detection. As DAS technology evolved, it was first trialed in Shell's unconventional tight gas wells in February 2009 to monitor plug setting, perforation shots and active clusters during fracking operation (Molenaar et al. 2012). In EOR application like SAGD, DAS provides an augmenting dataset correlating to production inflow phases (MacPhail et al. 2016) which would not be readily detectable in the temperature domain alone. Efforts like the one presented in this paper are underway to progress horizontal inflow profiling and inferred relative volumes which aids in understanding well productivity and efficacy of added inflow control devices (ICD). Unlike DTS, acoustic data is largely unaffected by temperature masking due to well completions. For events where insufficient temperature deviation are produced, DAS may be used to surveille for common industry challenges such as steam coning, gas ingression, loss of tubing/casing integrity and more. The emerging market segment for Carbon Capture and Underground Storage (CCUS) is poised to utilize DAS as one of the many leak detection toolkit for the injection monitoring wells.

Fiber optic measurements including Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) have been established as common tools to monitor the downhole condition during hydraulic fracturing treatment as well as during production. Several authors presented a methodology of quantitative interpretation for DAS and DTS data to estimate injected/produced fluid volume distribution among perforation clusters. The quantitative interpretation allows us to not only diagnose the stimulation efficiency but also optimize the completion design for subsequent fracturing jobs. This study investigates how completion parameters are correlated with fracturing stimulation performance based on the field application of DAS and DTS interpretation methodology. The field data from MIP-3H provided by the Marcellus Shale Energy and Environmental Laboratory is analyzed in this work. As previously presented, a DAS/DTS integrated interpretation method estimates fracture half-length distribution for each stage. In this approach, fractures are assumed to be created in a swarm pattern from each perforation cluster. We do not assign fractures only at the perforation cluster locations but assume that multiple fractures are initiated along a stage interval with much smaller spacing than cluster spacing. This fracture swarm model is supported by several field observations. Once the DAS interpretation estimates the injected fluid volume for each perforation cluster, by considering the fluid volume distribution as an input parameter for the DTS interpretation, the temperature inversion provides the half-length of each fracture. This interpretation approach allows us to estimate uniformity of the fracture half-length distribution. To statistically describe the fracture uniformity, a uniformity index is defined. The estimated uniformity index is compared with inflow rate for each stage to investigate how the uniformity of fracture distribution contributes to well performance. The inflow profile is estimated by interpreting the DTS data during production. The comparison shows that the stages with uniform fracture half-length distribution are more productive. This result implies that the stages more uniformly stimulated become more productive. By observing the relationship between the uniformity index and several completion parameters such as injection rate, total volume of injected fluid, proppant concentration and so on, we can investigate what parameter is more influential to the fracture stimulation efficiency. The statistical analysis illustrates that the uniformity of the fracture half-length distribution and high productivity are correlated with high injection rate. Based on this study, the injection rate would be one of the primary design parameters to maximize the fracturing stimulation performance in this field case. As demonstrated in this study, the evaluation of fracturing stimulation design based on the interpretation of DAS and DTS data would be an essential approach to optimize it.

The diatomite reservoir in the Belridge field, California, has been undergoing water injection for pressure maintenance to mitigate reservoir compaction and improve oil recovery. The reservoir is over one thousand feet thick with multiple layers, high compressibility, and very low permeability. Accurate placement of injection water across this massive reservoir is essential for balancing layer by layer voidage and reducing compaction. Therefore, monitoring sub-surface injection profile has become an important part of diatomite waterflood surveillance. However, monitoring profile with conventional wireline radioactive tracer tools has proven to be challenging due to the inability to access wellbores for logging because of scale build-ups or casing deformations. Over the past several years, a number of field trials have been performed to see if injection profile could be monitored using distributed temperature sensing (DTS) fiber-optic technology. If the technology works, then the strategy would be to install the DTS fiber early in the life of a well while the whole wellbore was still accessible. Once the fiber was in place, dynamic monitoring of injection profile could continue even if the well later developed scale build-ups, dog-legs, or other obstructions. Initial tests at Belridge were done with the DTS cable temporarily deployed on slickline. Once it was established that DTS could be used to measure injection profile in diatomite, several permanent installations were made in different areas of the field and in injectors with different mechanical configurations. Also, three different analysis methods were tried: stabilized injection; thermal restoration; and thermal tracer. In all cases, DTS-derived injection profiles were compared against wireline radioactive tracer profiles run at about the same time and under similar injection rates and pressures. Based on the technical success of the pilot, it was decided to scale-up to a 25-well program prior to full-field implementation in all 1000+ injectors in Belridge. This scaled-up program was focused on retrofitting DTS in existing injectors that still have an unobstructed well bore. These installations required the DTS cable to be run inside the injection tubing to the current effective depth of the well. However, the presence of the fiber-optic cable inside the tubing made the well unserviceable for future interventions such as coil-tubing clean-out, stimulation, or cased-hole logging operations. For this reason, design work is currently under way to run the DTS cable outside the injector casing at the time of initial drilling and completion of the well. This paper is a case study of the application of a new technology in solving surveillance issues in an old field. It covers the slow but methodical implementation of the DTS project, the challenges, and our solutions. It presents many examples of injection profiles derived from DTS measurements and a comparative evaluation of different interpretation techniques. The learnings from this project have potential for application in other secondary or tertiary recovery operations that require measurement of injection profile or continuous monitoring of the injection front.

This paper outlines the successful application of distributed temperature sensing (DTS) and fiber-optic-equipped coiled tubing (FOE-CT) in stimulating the first Carbon Dioxide (CO2) injector well in the UAE. A Real-Time Assisted Matrix Stimulation Engineering (RTA-MSE) workflow enabled accurate injection profiling over a 600-ft perforated interval, optimizing acid placement and volume. The treatment resulted in a more than five-fold increase in injectivity, with DTS confirming uniform post-treatment acid distribution. To mitigate coiled tubing (CT) exposure to the CO2 environment and avoid integrity risks, the wellbore fluid was initially displaced back to the formation using fresh water. In a single CT run, five DTS passes were recorded: DTS-1 for geothermal baseline, DTS-2 during freshwater injection to define the pre-treatment profile, and DTS-3 warm back to confirm flow distribution. Based on this data, the 28% hydrochloric acid treatment, enhanced with a nitrified stage, was optimized and pumped. DTS-4 and DTS-5—post-treatment injection and warm back—validated stimulation effectiveness. The CT was then safely retrieved, concluding the combined intervention and evaluation operation. This CO2 injector well—the first of its kind in the Middle East—was drilled into a saline aquifer. Post-drilling, it achieved an initial injectivity of 7 bpm at 1,000 psi surface injection pressure. Distributed Temperature Sensing (DTS) profiling identified three distinct injection zones across the 600-ft perforated interval. Zones 2 and 3, located in the upper section, showed limited injectivity, which correlated with petrophysical interpretation and water injection simulation. In contrast, Zone 1, the lowermost section, exhibited uniform injection. Given the vertical well architecture, a nitrified acid stage was incorporated into the treatment to enhance coverage of the upper zones. Post-stimulation DTS data confirmed a significantly improved and uniform injection profile across all zones. As a result, the well's injectivity index increased by a factor of 5. This case validates the effectiveness of fiber-optic-enabled coiled tubing with real-time DTS in optimizing acid placement and improving zonal coverage in challenging CO2 injection environments. The methodology offers a replicable stimulation workflow for similar injector wells across the region, advancing stimulation design and monitoring practices in the petroleum industry. This paper presents the first documented case in the UAE of using DTS and downhole measurements to evaluate and optimize acid stimulation in a vertical CO2 injector. By profiling injection across a 600-ft perforated interval in real-time, the study demonstrates how DTS-enabled workflows can ensure uniform stimulation and significantly enhance injectivity, offering a new benchmark for matrix acidizing in CO2 injection wells across the industry.

The article discusses the possibility of diagnosing the multiphase flow regime in the multilayered reservoir by using DTS (distributed temperature sensing) data. The analysis of the theoretical and actual curves of temperature build up and drawdown, corresponding to the main modes of multiphase flow of formation fluids are given in this article. The possibility of diagnosis of the multiphase flow regime is found based on analysis and interpretation of the characteristics of temperature build-up and drawdown in different intervals of the reservoir at the start of the well or shut in, or by changing opening degree of the choke. The possibility of diagnosing water breakthrough (WBT) intervals, based on the analysis of the changes in temperature curves according to the DTS is shown. For a more detailed analysis and interpretation of temperature change curves in the wells more frequent DTS measurements are required. It is necessary to conduct a comparative analysis of the dynamics of the temperature and pressure redistribution in the productive zone of the well, with the results of geophysical logging, production logging, taking samples of reservoir fluids from different zones of productive layers in the multilayered reservoir, moisture metering, hydrometry and others.

[1] Distributed temperature sensing (DTS) was used to map spatial and temporal changes in temperature on a 25 m by 6 m lakebed area in the winter (February), spring (May), and summer (August) of 2012. A constant and high discharge of groundwater with the average temperature of around 8°C to the lake will result in either lower (summer) or higher (winter) daily temperatures and reduce temperature variability at the sediment-water interface (SWI). DTS data were used as a proxy for groundwater discharge using three metrics; daily minimum temperature, diel amplitude, and daily standard deviation of temperature. During the seasons, the daily minimum temperatures at the SWI indicate a discharge zone 4–6 m offshore. From winter to summer, the extent of this zone changes and the SWI temperatures also show a shift of discharge locations toward the shore. Fluxes estimated on the basis of vertical temperature profiles from the top 50 cm of the lakebed and seepage meters in August compare well with the locations of the high-discharge zones detected by the DTS in the same period, giving confidence in the ability of the method to map both the areas and spatial variability of groundwater discharge to lakes. Compared to February, the DTS was able to detect new relatively cold temperature zones at the SWI in May and August indicating that groundwater discharge to the lake changes over time and that DTS can be used to monitor temporal variability in areas of discharge.

Where is that CO2 flowing? Using Distributed Temperature Sensing (DTS) technology for monitoring injection of CO2 into a depleted oil reservoir

This article is dealing with an optical fiber refractive index design optimized for utilization in DTS (Distributed Temperature Sensing) measurements. Presented optical fiber uses wavelength of 850 nm for communication purposes and 1060 nm for sensory operation. The aim of this work is to design an optical fiber with redistribution of the optical field at 850 nm similar to communication multi-mode optical fiber 50/125 μm and for wavelength of 1060 nm the redistribution of the optical field will be shifted closer to the core-cladding boundary to increase its sensitivity to temperature. Optical properties obtained from fiber design are compared with standard multi-mode optical fiber with graded refractive index to ensure that new optical fiber design has better sensing characteristics, but still keeps good enough communication properties at the same time.

This work presents an experimental study conducted using a modular flow-loop apparatus to evaluate flow diagnostics with Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) across simulated well scenarios. Dedicated simulators, including horizontal and vertical injection and production wells, enable repeatable emulation of subsurface dynamics such as steady-state and transient flow regimes, leak inflow/outflow, time-varying injectivity and productivity, and intervention responses. Each simulator incorporates programmable flow conditions with synchronized acquisition of DAS and DTS data, co-registered with reference pressure and flow instrumentation. In addition to passive sensing, we investigate active modalities that strengthen flow-signal detectability, reduce interpretation ambiguity, and increase confidence in physics-based flow profiling. In active DAS, low-frequency flow stimulation generates broadband harmonics that enhance spectral content and signal-to-noise ratio. For active DTS, a novel distributed anemometry approach uses the temperature response to a controlled, steady heat input to estimate the flow velocity profile. The results provide experimental validation and example self-learning flow allocation workflows for distributed sensing as a quantitative diagnostic tool for transient well dynamics. With high-resolution sensing, operators gain immediate insight into downhole flow phenomena, supporting on-the-fly data-driven adjustments to interventions and robust assessments of zonal performance in complex subsurface environments.

Over the last two decades, there has been advances in downhole monitoring in oil and gas wells with the use of Fiber-Optic sensing technology such as the Distributed Temperature Sensing (DTS). Unlike a conventional production log that provides only snapshots of the well performance, DTS provides continuous temperature measurements along the entire wellbore. Whether by fluid extraction or injection, oil and gas production changes reservoir conditions, and continuous monitoring of downhole conditions is highly desirable. This research study presents a tool for real-time quantification of production from individual perforation clusters in a multi-stage shale well using Artificial Intelligence and Machine Learning. The technique presented provides continuous production log on demand thereby providing opportunities for the optimization of completions design and hydraulic fracture treatments of future planned wells. A Fiber-Optic sensing enabled horizontal well MIP-3H in the Marcellus Shale has been selected for this work. MIP-3H is a 28-stage horizontal well drilled in July 2015, as part of a Department of Energy (DOE)-sponsored project - Marcellus Shale Energy & Environment Laboratory (MSEEL). A one-day conventional production logging operation has been performed on MIP-3H using a flow scanner while the installed Fiber-Optic DTS unit has collected temperature measurements every three hours along the well since completion. An ensemble of machine learning models has been developed using as input the DTS measurements taken during the production logging operation, details of mechanical logs, completions design and hydraulic fracture treatments data of the well to develop the real-time shale gas production monitoring tool.

This research presents a new method to verify the measurements of surface fluxes and the heat balance at a lake surface, by means of Distributed Temperature Sensing (DTS) measurements from 0.5 m above to 1.5 m below the surface. Using a polyvinyl chloride hyperboloid construction, a floating standalone measuring device was developed. Being an open construction, it is almost insensitive to direct radiation. With this construction, a spiral‐shaped fiberoptic cable setup was created that obtained temperature measurements with a vertical spatial resolution of 0.0002 m and a temporal resolution of 1 min. DTS measured the detailed variations in air and surface water temperature. The new method was tested in the deep Lake Kinneret (Israel) from 6 to 9 Oct 2011 and in the shallow Lake Binaba (Ghana) from 24 to 28 Oct 2011. With the developed method, it is possible to capture the heat storage change in the top water layer, and therefore verify the water surface heat balance on a time scale of several minutes. Furthermore, a comparison was made between the measured temperature profiles of the airwater interface in Lake Kinneret and Lake Binaba. It was shown that the usage of DTS measurements for the verification of surface energy balance was applicable for Lake Kinneret, but probably not suitable for the conditions in the shallow Lake Binaba. In the latter, heat storage changes near the lake surface were not only caused by surface energy fluxes, but by internal heat waves and currents that bring cooler water to the upper layer.

As part of the strategic initiative to develop main reserves in Jambaran field in East Java, Indonesia, to supply gas and drive the national economy, six gas producers were completed targeting 300 MMscf/D of total production. The main challenge consisted in efficiently perforating underbalanced a minimum of 800 ft in each well. To this end, coiled tubing (CT) equipped with fiber optic (FO) and deployment under pressure were implemented, rigless; this was a first in the country. Understanding of zonal contribution in those long intervals early in the life of the wells was key to addressing any potential concerns over reservoir productivity and critical to the field management. Due to the high CO2and H2S contents of formation fluids (up to 34% and 10,000 ppm, respectively), traditional production logging was impossible. Instead, distributed temperature sensing (DTS) and downhole pressure point measurements through FO CT telemetry were jointly used to compute the flow distribution along each perforated interval. The acquired data were inverted and analyzed using a pressure-temperature-rate transient analysis (PTRA) software. In this field, reservoir K is a carbonate formation with a net thickness of ~1,450 ft and an average permeability of 46 md. Gas rates up to 60 MMscf/D were expected in each well. In such extreme downhole environment, DTS on FO CT was selected due to the possibility to circulate inhibitor throughout the operation to protect the CT pipe and downhole equipment. In addition, it enabled logging at gas rates as high as 60 MMScf/D without CT movement, which would not have been possible using wireline or slickline conveyance. In each well, a series of carefully planned shut-in and constant flowing phases were performed, during which temperature profiles and point pressure data were interpreted both qualitatively and quantitatively. A representative thermal model was built in the PTRA software utilizing reservoir properties, downhole point measurements, and surface well test data. Quantitative DTS interpretation indicated the same behavior in all six wells, with an uneven gas production along the perforated intervals. The minimal contributions observed from the upper section of the formation were attributed to low permeability whereas the high pressure drop observed across the bottom section was found indicative of a higher skin. Those findings will be key to future field developments in reservoir K. The use of CT equipped with FO for DTS proved a reliable alternative to production logging in high-rate gas producers. This study provided critical insights on the completion strategy performance and new considerations to minimize formation damage during future drilling campaigns. It also enabled establishing new best practices for DTS production logging in high-rate producers, in particular with respect to recommended drawdown conditions to obtain reliable readings.