Temperature monitoring using Distributed Temperature Sensing (DTS) technology

The variation of temperature profile of the sandface and wellbore offers important indicators for the occurrence of various downhole phenomena, as functions of reservoir formation and fluid properties. This paper aims to investigate the assimilation of temperature and production data for robust and efficient estimation of reservoir formation properties and fluid characterization. Very few previous work in the literature used Distributed Temperature Sensing (DTS) data for the characterization of the reservoir fluid and geostatistical description. The main contribution of this work lies in the proposed methodology for integration of temperature data from DTS systems to obtain a robust estimation of the reservoir fluid description, as well as introducing the integration of temperature data as an alternative and/or complementary data for integrative reservoir characterization. Two synthetic reservoir examples are investigated. In the first example, we focus on resolving the geostatistical description of a 3D multi-phase reservoir under water flooding. An ensemble-based data assimilation algorithm is used to compare the characterization of reservoir formation porosity and permeability by integration of temperature profile and well production data as opposed to the integration of production logging tool (PLT) data. Our results show that the DTS temperature data shows good potential as an alternative to the PLT data for reservoir rock characterization, although there may be a risk of model overfitting due to the large amount of data. In the second example, we attempt to estimate the original composition of the reservoir fluid as well as reservoir rock properties using downhole temperature profile data. A relatively simple multi-layer radial reservoir model is considered in this case. However, in order to honor the physical bounds on the various model parameters, a constrained ensemble-based data assimilation algorithm based on Lagrange multipliers is adopted. The computational results show that the original reservoir fluid composition could be excellently estimated for a case with known reservoir properties. Presence of uncertainty in the reservoir formation properties resulted in an poor estimation of the original reservoir fluid composition.

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

In steam assisted gravity drainage (SAGD), temperature instrumentation is widely used to understand steam placement across openhole liners in producer and injector wells. The accuracy of temperature readings is crucial when monitoring wellbore integrity and optimizing production. While distributed temperature sensing (DTS) on fiber-optic cables has been widely used in temperature monitoring, challenges consistently exist regarding accuracy. Several trials over a 2-year period were completed to quantify the accuracy of DTS systems. Each trial employed different operating conditions and instrumentation: Case Study 1: Dual-laser DTS and thermocouples were permanently deployed in a newly drilled SAGD producer. The well was heated from geothermal to 240°C. Newly deployed thermocouples were compared against newly deployed fiber-optic cables. Case Study 2: Dual-laser DTS temperature measurements were compared across a 1 dB point loss at a maximum optical budget of 13 dB. Case Study 3: Dual-laser DTS vs. single-laser DTS vs. new thermocouples comparisons were made. Case Study 4: Thermocouples and dual-laser DTS for a mid-life SAGD injector and producer were compared for accuracy after two years of operation. Case Study 5: An independent temperature log containing dual-laser DTS was used to quantify the thermocouple temperature discrepancy on a SAGD producer in operation for 7 years. The results of these case studies allowed Devon to determine several important learnings, as well as a troubleshooting methodology for evaluating DTS accuracy. When properly installed and calibrated, dual-laser systems are accurate up to ±2°C over the full range of SAGD operating temperatures for stable operating conditions. During the trial period, DTS was shown to maintain accuracy for 2 years. When comparing the accuracy of temperature systems, it is recommended to compare against other known metrics during falloffs. New thermocouples are still considered the most accurate measurement; however, legacy thermocouples are susceptible to drift. Independent temperature logs have proven to be a valuable tool for assessing legacy instrumentation accuracy for thermocouples and DTS.

Distributed Fiber optic sensing system is a unique tool for the evaluation of distributed temperature over several kilometers. It is a powerful diagnostic instrument for the identification and localization of potential problems, such as leakages in pipelines and dykes, hot-spots in high-voltage cables and other events that create temperature anomalies. Such distributed temperature sensing (DTS) systems have the advantage of being relatively easy to deploy over long pipeline sections and have been shown to detect leakages events with good accuracy and reliability. However, when distributed fiber optic sensing systems are deployed in security-critical applications, where availability and reliability are crucial, it is important to continuously verify and assess the correct functioning and reliability of the whole system, including the sensing cables, the measurement system, the data analysis software and the alert transmission. In the past, such testing have been performed periodically by the pipeline personnel, but testing frequencies are typically low, e.g. once per year. The DTS Automated Trip Testing System is a fully independent device that is able to produce a controlled and localized thermal anomaly (hot spot or cold spot) and verify its correct detection. This allows a continuous verification of the DTS system reliability and functionality and a periodic statistical evaluation of the confidence level (proven by experience SIL rating). This paper will present more specifically the development, the functioning and deployment, and its applications of an automated system and method for testing the efficacy and reliability of distributed temperature sensing (DTS) systems, in particular those DTS systems used for pipeline leakage detection.

W orldwide emissions of CO2 continue to increase, and prudence dictates that technologies be developed to help limit this trend. One of several ways to attenuate the increase of CO2 in the atmosphere is to sequester it.[*][1] The technology for doing so exists. The injection of CO2 into oil fields is having economically beneficial effects while at the same time sequestering CO2. In addition, under the surface of the earth in the United States and elsewhere, many structures that once were filled with fossil fuels have been exploited, leaving space that might be used to store CO2. In the United States, some of the structures from which natural gas has been extracted are being used to safely store high-pressure gas produced elsewhere. In the exploitation of petroleum fields, about 20 to 40% of the oil can usually be obtained. In the early days, production was often enhanced in neighboring wells when water was forced down into one of them. Later it was discovered that CO2 under pressure was also effective. In many oil wells, pressures and temperatures are high enough that CO2 becomes a mobile fluid that is miscible with oils having densities of about 0.90 grams per cubic centimeter or less. These liquids tend to move toward lower pressures in production wells, and with this technique an additional 10 to 15% of the oil in an oil field can often be produced. Much of the CO2 is recycled, but part of it remains in the oil-bearing formations. The net result can be profitable use of CO2 and sequestration of some of it. In the United States in 1998, CO2 had a major role in producing 6% of domestic crude oil. Later this year, a project using CO2 will begin at Weymouth Sasketchawan in Canada. A field there that has been producing oil since 1952 will receive 5000 metric tons of CO2 per day via a 300-kilometer pipeline. The source will be the Dakota Gasification Company, located in Beulah, North Dakota. During the course of a multiyear injection, 20 million metric tons of CO2 will be sequestered, and an extra 130 million barrels of oil will be produced. An international team will monitor the behavior of the field, and details of their findings will be made widely available. Another benefit could be that more attention will be focused on the Dakota Gasification Company. Among the plant's other outputs are electricity, methane, hydrogen, ammonium sulfate, phenols, and cresols. Its principal inputs are liquid oxygen, steam, and lignite coal. Almost all of the efforts to use CO2 in enhanced oil recovery have occurred in the United States. A notable exception is a large Bati Roman field in southeast Turkey. Its heavy oil has high-molecular-weight components, and primary production was capable of achieving an ultimate recovery of only 1.5% of the original oil. Injection of CO2 was successful in increasing production. Total miscibility was not achieved, but a large volume of CO2 dissolved in the oil and its viscosity decreased from 1000 centiposes (cp) to less than 100 cp. This facilitated flow, and a recovery of 6.5% is expected. The present amount of geological sequestration of CO2 is small in comparison with emissions. However, the ultimate global potential is substantial. In addition to its use in petroleum fields, a substantial volume of CO2 could be sequestered in deep unmineable coal and in depleted natural gas fields. A 131-page report commissioned by the International Energy Agency (IEA) and supported in part by the U.S. Department of Energy has included estimates of what might ultimately be achieved. [†][2] The IEA report estimates that the ultimate storage capacity of the oil and gas fields equates to over 125 years of total current CO2 emissions from fossil-fueled power plants. A major source of CO2 is the combustion of fossil fuel in power plants. Coal is the major and the cheapest fuel, but CO2 formed by burning it is polluted. The gas must be cleaned and pressurized before injection. The total cost of these procedures is roughly $53 per metric ton or more. This cost is a barrier to segregating it. A vigorous program aimed at cutting the cost of cleaning CO2 emitted by power plants should have a high priority and adequate funding. Success in such a program would be an important help in reducing the overall costs of whatever sequestration methods were ultimately employed. Controversy exists about the possible extent of the contribution of CO2 to present and future global warming. However, if international agreements are implemented to attenuate the buildup of atmospheric CO2, sequestration of it in unused or abandoned fossil hydrocarbon fields is one good step to take. [1]: #fn-1 [2]: #fn-2

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.

<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>

Large Volume CO2 Storage and Plume Management in the Southeastern U.S.; Reservoir Characterization and Simulation

Raman spectra distributed temperature sensing (DTS) by fiber‐optic cables has recently shown considerable promise for the measuring and monitoring of surface and near‐surface hydrologic processes such as groundwater–surface water interaction, borehole circulation, snow hydrology, soil moisture studies, and land surface energy exchanges. DTS systems uniquely provide the opportunity to monitor water, air, and media temperatures in a variety of systems at much higher spatial and temporal frequencies than any previous measurement method. As these instruments were originally designed for fire and pipeline monitoring, their extension to the typical conditions encountered by hydrologists requires a working knowledge of the theory of operation, limitations, and system accuracies, as well as the practical aspects of designing either short‐ or long‐term experiments in remote or challenging terrain. This work focuses on providing the hydrologic user with sufficient knowledge and specifications to allow sound decisions on the application and deployment of DTS systems.

Abstract. Internal erosion is the cause of a significant percentage of failure and incidents involving both dams and river embankments in many countries. In the past 20 years the use of fibre-optic Distributed Temperature Sensing (DTS) in dams has proved to be an effective tool for the detection of leakages and internal erosion. This work investigates the effectiveness of DTS for dike monitoring, focusing on the early detection of backward erosion piping, a mechanism that affects the foundation layer of structures resting on permeable, sandy soils. The paper presents data from a piping test performed on a large-scale experimental dike equipped with a DTS system together with a large number of accompanying sensors. The effect of seepage and piping on the temperature field is analysed, eventually identifying the processes that cause the onset of thermal anomalies around piping channels and thus enable their early detection. Making use of dimensional analysis, the factors that influence this thermal response of a dike foundation are identified. Finally some tools are provided that can be helpful for the design of monitoring systems and for the interpretation of temperature data.

The healthcare sector is responsible for 4.4% of global greenhouse gas (GHG) emissions. To limit global temperature rise by 1.5 °C, as called for in the Paris Agreement, GHG emissions will need to be significantly reduced. As climate change has been labelled the greatest threat to global health in the twenty-first century, all healthcare professionals must attempt to promote sustainable practice where possible. The British Society of Dermatological Surgery sustainability guidelines published in 2022 advocate multiple strategies for improving sustainability in skin cancer surgery, including a reduction of activity via prevention measures, low-carbon alternatives, operational resource use and research and innovation. It is recommended that ‘see-and-treat clinics’ should be offered where staff and facilities are available, as one of several methods to lower the carbon footprint of dermatological surgery. We performed a cross-sectional study in a single tertiary dermatology department, focusing on carbon dioxide (CO2) emissions associated with travel to and from skin surgery appointments from 1 January 2022 to 31 December 2022. Our dermatology department is located in an urban area and also receives referrals from rural locations. The distance from the patient’s home to the hospital was calculated in kilometres using Google Maps. Total CO2 emissions were calculated using an online calculator recommended by the Environmental Protection Agency of Ireland and were reported in metric tonnes of CO2. Fuel consumption was based on the average car with unknown fuel. In total, 2358 procedures were performed on 2184 patients, 54% of whom were male (n = 1180). The total distance travelled by patients was 109 787.94 km, averaging 50.27 km per patient (range 1.3–168). This generated 18.74 metric tonnes of CO2 emissions. Eighteen per cent (n = 389) of patients underwent surgical procedures on the same day as their outpatient clinic. Same-day surgery led to a reduction of 35 275 km, averaging 90.68 km per patient (range 1.3–120). This represented a reduction of 6.02 metric tonnes of CO2 emissions. This is equivalent to the CO2 emitted from six transatlantic flights. In our department, absorbable sutures are used, where possible, to reduce unnecessary travel to our department or to a general practice for suture removal. Results for benign lesions are communicated via letter, to minimize return to the clinic. This study highlights the reduction in CO2 emissions associated with same-day dermatological surgery. The limitations of this study include an assumption of travel to and from hospital appointments by car and of travel from the address stated in patient records. Dermatologists should consider the environmental impact of skin surgery and implement sustainable options when service planning.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 23948, ’Full-Scale Testing of Distributed-Temperature Sensing in Flexible Risers and Flowlines,’ by Nick Weppenaar, Thomas Iversen, and Bo Andersen, NOV Flexibles, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission. This paper presents results from full-scale testing of a flexible riser equipped with embedded sensors for distributed-temperature sensing (DTS). Testing includes monitoring of accessories mounted on the riser, monitoring of hot spots such as trenched sections of the riser, and detection of breaches of the outer sheath. Applications of such a condition-monitoring system to riser-integrity management (RIM) and production optimization are worth examining. Introduction With the increasing use of flexible-pipe technology—driven by the move of new offshore fields to deeper, more-marginal, and more-challenging conditions— the need for systematic management of the flexible pipes is becoming more apparent. In particular, the full implementation of RIM plays a vital role in ensuring an efficient and safe operation. Riser-condition monitoring and inspection form an important part of integrity management, together with processing and analysis of the monitored data. In that respect, the recently developed technology within optical-fiber monitoring offers unique possibilities for quantifying the integrity of flexible risers during their service life. The advantage of an embedded monitoring system is the ability to survey the riser condition continuously, thus enabling operators to detect potential damages in a timely fashion. The embedded system will allow monitoring in critical areas (e.g., under a bend stiffener or inside an I-tube) where access is limited for externally mounted monitoring systems. Temperature-Monitoring System The temperature-monitoring system is a DTS system that uses a standard multimode optical fiber to measure the temperature at all points along the fiber with a given spatial resolution. The principle of implementation into a flexible pipe is shown in Fig. 1. The fiber is mounted on top of the outer tensile layer while being protected from crushing forces. The specific implementation that has been achieved allows for temperature measurements with a spatial resolution in the longitudinal direction of the pipe of approximately 8 cm. Currently, this can be implemented in pipes that are up to approximately 5 km in length, and the sample time can be as fast as 10 seconds per fiber. If a longer pipe length needs to be monitored, this can be achieved at the expense of spatial resolution or temperature resolution. For the present series of tests, the fiber length is approximately 200 m, which allows for a high temperature resolution. The system measures every 10 seconds, with a temperature resolution of approximately 0.1°C and a spatial resolution of approximately 15 cm.

[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.

Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) measurements are technologies which are adding some benefits in the aim to replace or complete traditional logging measurements like noise logging tools (NLT) or production logging tools (PLT). The aim of well integrity interventions using distributed fiber optic sensing (DFOS) is to significantly reduce the duration and the cost of these operations, and to provide additional information in comparison to traditional logging tool. The combination of DAS and DTS can offer both qualitative and quantitative information regarding fluid dynamics in the context of well integrity investigation, as the flow characteristics (intensity of turbulences). In addition to acoustic (high frequency DAS) and temperature (DTS) monitoring for leak detection, we propose to use DTGS (Distributed Temperature Gradient Sensing) with low frequency DAS (&amp;lt; 1 Hz) to monitor leaks on the completion tubing of a well. The main advantage of using DTGS with DAS is its sensitivity to small leaks, including the direction of propagation of the leak.

Permanent distributed temperature sensing (DTS) using fiber-optic technology provides measurements over the complete length of the fiber in the wellbore. The temperature profiles can be monitored at surface in real time, minimizing the need for production logs, preventing deferred production losses, decreasing well interventions, and reducing operating costs. This technology has been applied by Apache North Sea Ltd in the Forties field to monitor and optimize the performance of two wells producing by gas lift in the Delta platform and, at the same time, examine their completion integrity. To accomplish these objectives, a hybrid fiber-optic electrical cable was installed in two Forties wells, allowing the continuous measurement of temperature and acquisition of pressure data from a downhole gauge located below the deepest gas-injection point. The combined benefit of reducing both the number of well interventions, and thus eliminating the associated QHSE risks, and the operating costs made this well monitoring strategy the appropriate one in this mature field. The analysis and interpretation of downhole pressure and DTS data provided rapid feedback to the platform production team regarding the status of the well, allowing a better and more informed decision-making process. In this paper, we outline the deployment of the hybrid DTS system and describe the analysis performed in each of the two wells. Data handling, analysis, and interpretation are described as well as the methodology and workflow for well monitoring and optimization using permanently installed DTS.