Distributed Temperature Sensing Technology Research Articles

High‐Resolution Field Measurement of Soil Heat Capacity and Changes in Soil Moisture Using a Dual‐Probe Heat‐Pulse Distributed Temperature Sensing Approach

AbstractIncreasing interest in studying the variability of soil water content and its spatial scale dependency necessitates the development of new techniques to accurately monitor soil water over a wide range of spatial scales. Distributed Temperature Sensing (DTS) techniques offer unprecedented opportunities to measure temperature with a spatial resolution of a few centimeters over several kilometers, which can be used to measure soil moisture. This study is the first of its kind that investigates under field conditions the feasibility of combining the Dual‐Probe Heat‐Pulse (DPHP) technique with the DTS technology to measure soil thermal properties and variation in soil moisture. A field experiment was conducted over a 30 m transect in the Lake Wheeler Field laboratory in Raleigh, NC. Three different DPHP sensors were constructed from combinations of different fiber optic cables and heating elements and were tested to assess their performance and the effect of their construction characteristics on their accuracy. Measurements were taken over different soil moisture conditions and the system performance was compared against independent soil water content sensors. The system was able to track changes in soil water content with a mean RMSE of 0.02 m3 m−3 using the optimal DPHP sensor. The key advantage of the tested system is that it does not need any site‐specific calibrations typically required for other DTS‐based systems. The findings of this study provide some practical information and measures that need to be taken for successful DTS‐DPHP construction and application under field conditions.

Real-Time Well-Integrity Monitoring Using Fiber-Optic Distributed Acoustic Sensing

Summary Proper cemented casing strings are a key requirement for maintaining well integrity, guaranteeing optimal operation and safe provision of hydrocarbon and geothermal resources from the pay zone to surface facilities. Throughout the life cycle of a well, high–temperature/high–pressure changes in addition to shut–in cyclic periods can lead to strong variations in thermal and mechanical load on the well architecture. The current procedures to evaluate cement quality and to measure downhole temperature are mainly dependent on wireline–logging campaigns. In this paper, we investigate the application of the fiber–optic distributed–acoustic–sensing (DAS) technology to acquire dynamic axial–strain changes caused by propagating elastic waves along the wellbore structure. The signals are recorded by a permanently installed fiber–optic cable and are studied for the possibility of real–time well–integrity monitoring. The fiber–optic cable was installed along the 18⅝–in. anchor casing and the 21–in.–hole section of a geothermal well in Iceland. During cementing operations, temperature was continuously measured using distributed–temperature–sensing (DTS) technology to monitor the cement placement. DAS data were acquired continuously for 9 days during drilling and injection testing of the reservoir interval in the 12¼–in. openhole section. The DAS data were used to calculate average–axial–strain–rate profiles during different operations on the drillsite. Signals recorded along the optical fiber result from elastic deformation caused by mechanical energy applied from inside (e.g., pressure fluctuations, drilling activities) or outside (e.g., seismic signals) of the well. The results indicate that the average–axial–strain rate of a fiber–optic cable installed behind a casing string generates trends similar to those of a conventional cement–bond log (CBL). The obtained trends along well depth therefore indicate that DAS data acquired during different drilling and testing operations can be used to monitor the mechanical coupling between cemented casing strings and the surrounding formations, hence the cement integrity. The potential use of DTS and DAS technology in downhole evaluations would extend the portfolio to monitor and evaluate qualitatively in real time cement–integrity changes without the necessity of executing costly well–intervention programs throughout the well's life cycle.

Quantification Assessment of Extraneous Water Infiltration and Inflow by Analysis of the Thermal Behavior of the Sewer Network

Infiltration and inflow (I/I) of unwanted water in separate urban sewer networks are critical issues for sustainable urban water management. Accurate quantification of unwanted water I/I from individual sources into a sewer system is an essential task for assessing the status of the sewer network and conducting rehabilitation measures. The study aim was to quantify extraneous water I/I into a sanitary sewer network by a temperature-based method, i.e., fiber-optic distributed temperature sensing (DTS), which was applied for the first time in a separate sewer network of a catchment in Trondheim, Norway. The DTS technology is a relatively new technology for sewer monitoring, developed over the past decade. It is based on continual temperature measurement along a fiber-optic cable installed in the sewer network. The feasibility of this method has been tested in both experimental discharges and for the rainfall-derived I/I. The results achieved from the monitoring campaign established the promising applicability of the DTS technique in the quantification analysis. Furthermore, the application of this method in quantifying real-life, rainfall-derived I/I into the sewer system was demonstrated and verified during wet weather conditions.

Feasibility of Locating Leakages in Sewage Pressure Pipes Using the Distributed Temperature Sensing Technology

The cost effective maintenance of underwater pressure pipes for sewage disposal in Austria requires the detection and localization of leakages. Extrusion of wastewater in lakes can heavily influence the water and bathing quality of surrounding waters. The Distributed Temperature Sensing (DTS) technology is a widely used technique for oil and gas pipeline leakage detection. While in pipeline leakage detection, fiber optic cables are installed permanently at the outside or within the protective sheathing of the pipe; this paper aims at testing the feasibility of detecting leakages with temporary introduced fiber optic cable inside the pipe. The detection and localization were tested in a laboratory experiment. The intrusion of water from leakages into the pipe, producing a local temperature drop, served as indicator for leakages. Measurements were taken under varying measurement conditions, including the number of leakages as well as the positioning of the fiber optic cable. Experiments showed that leakages could be detected accurately with the proposed methodology, when measuring resolution, temperature gradient and measurement time were properly selected. Despite the successful application of DTS for leakage detection in this lab environment, challenges in real system applications may arise from temperature gradients within the pipe system over longer distances and the placement of the cable into the real pipe system.

Use of Distributed Temperature Sensing Technology to Characterize Fire Behavior.

We evaluated the potential of a fiber optic cable connected to distributed temperature sensing (DTS) technology to withstand wildland fire conditions and quantify fire behavior parameters. We used a custom-made ‘fire cable’ consisting of three optical fibers coated with three different materials—acrylate, copper and polyimide. The 150-m cable was deployed in grasslands and burned in three prescribed fires. The DTS system recorded fire cable output every three seconds and integrated temperatures every 50.6 cm. Results indicated the fire cable was physically capable of withstanding repeated rugged use. Fiber coating materials withstood temperatures up to 422 °C. Changes in fiber attenuation following fire were near zero (−0.81 to 0.12 dB/km) indicating essentially no change in light gain or loss as a function of distance or fire intensity over the length of the fire cable. Results indicated fire cable and DTS technology have potential to quantify fire environment parameters such as heat duration and rate of spread but additional experimentation and analysis are required to determine efficacy and response times. This study adds understanding of DTS and fire cable technology as a potential new method for characterizing fire behavior parameters at greater temporal and spatial scales.

Development and Improvement of an Intelligent Cable Monitoring System for Underground Distribution Networks Using Distributed Temperature Sensing

With power systems switching to smart grids, real-time and on-line monitoring technologies for underground distribution power cables have become a priority. Most distribution components have been developed with self-diagnostic sensors to realize self-healing, one of the smart grid functions in a distribution network. Nonetheless, implementing a real-time and on-line monitoring system for underground distribution cables has been difficult because of high cost and low sensitivity. Nowadays, optical fiber composite power cables (OFCPCs) are being considered for communication and power delivery to cope with the increasing communication load in a distribution network. Therefore, the application of distributed temperature sensing (DTS) technology on OFCPCs used as underground distribution lines is studied for the real-time and on-line monitoring of the underground distribution power cables. Faults can be reduced and operating ampacity of the underground distribution system can be increased. This paper presents the development and improvement of an intelligent cable monitoring system for the underground distribution power system, using DTS technology and OFCPCs as the underground distribution lines in the field.

Using distributed temperature sensing (DTS) technology in acid gas injection design

The use of slickline distributed temperature sensing (SL-DTS) technology is becoming widespread due to its ease of operation and ability to acquire real-time multiple temperature traces inside the wellbore. Injection of treated acid gas (TAG)—a mixture of CO2 and H2S—into geologic formations has become an attractive technical and economic option for oil and gas producers and processors who are faced with regulations concerning excess sulfur and greenhouse gas emissions. Acid gas injection (AGI) into geologic formations is more economical and more flexible in dealing with varying TAG compositions than sulfur recovery units (SRUs) using the Claus process. SRUs do not achieve air quality standards and have high operation and maintenance costs. In addition, there is low demand for sulfur and sulfur disposal costs are high. The results of the analysis of SL-DTS data acquired in conjunction with step rate and pressure falloff (PFO) tests are presented in this paper. These tests were conducted to evaluate the injection potential of geologic formations. The injection zone consisted of a carbonate formation characterized by Karst features, vugs, and natural fractures. The SL-DTS data during the initial injection flow rate for the step rate test (SRT) indicated that high permeability zones accepted fluid at lower injection rates. An increasing number of discrete zones began to accept fluid as the injection rate was increased. The results of the SRT provided the fracture pressure of the formation. This information was used to design an AGI program that would avoid fracturing the formation while allowing for the required volume of TAG to be injected. The results of the PFO test provided information on the reservoir pressure and permeability and also indicated the presence of one or more hydraulic fractures. This case study of SL-DTS measurements made during a SRT and a PFO test for the design of an AGI well provides valuable insights into the potential of DTS technology and its use in AGI and carbon capture/sequestration (CCS) operations. Its findings could be applied to analyze injection potential of geological formations not only for AGI projects but also for CCS, and CO2 enhanced oil recovery opportunities.

Fracture-Stimulation Diagnostics in Horizontal Wells Through Use of Distributed-Temperature-Sensing Technology

Summary Horizontal wells with hydraulic-fracture treatments have proved to be an effective method for developing unconventional oil and gas reservoirs. During the past several years, fracturing methods have evolved and improved rapidly; however, there still exist many uncertainties in fracture design. Several fracture-diagnostic techniques have been developed to improve the understanding of the fracturing process. In this study, after reviewing the application and limitations of the current fracture-diagnostic techniques, we describe the application of distributed-temperature-sensing (DTS) technology as a complementary tool for real-time fracture diagnostics. DTS technology has enabled us to observe the dynamic-temperature profile along the wellbore during the treatment. However, quantitative interpretation of dynamic-temperature data is very challenging and requires in-depth mathematical modeling of heat and mass transfer during the treatment. We have developed a thermal model to simulate the temperature behavior along the wellbore during the treatment, as well as during the shut-in period. This model takes into account the effect of all significant thermal processes involved, including conduction and convection. Examples are presented to illustrate how this model can be applied for fracture-stimulation diagnostics. Estimation of the fracture-initiation points, number of created fractures, and distribution of stimulation fluid along each isolated zone are the problems for which DTS technology can help obtain answers. The effectiveness of isolation can also be diagnosed by DTS technology because the heat-transfer mechanism changes when convection caused by leaking in isolation occurs. This information can be used for more-accurate fracture modeling and better estimation of fracture conductivity and fracture geometry and, therefore, to optimize future treatments and also to evaluate the well performance.

지중 배전계통 적용을 위한 광복합 케이블 실시간 감시시스템 개선

Since power system is switching to smart grid, on-line monitoring technology has become necessary for underground distribution power cable. Therefore, the application of DTS(Distributed Temperature Sensing) technology using OFCPC(Optical Fiber Composite Power Cable) capable of monitoring underground distribution power cables has been developed. These can bring about reductions in faults and increases in operating capacity of underground distribution system. To date, the test-bed of optical fiber composite power cable on-line monitoring system has been constructed. Then, matters to be improved have been drawn through verification experiments. This paper presents the improvement and experiment results of the optical fiber composite power cable on-line monitoring system to apply to underground distribution lines in the field.

DTS Technology: Improving Acid Placement

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 145055, ’DTS Sensing: An Emerging Technology Offers Fluid Placement for Acid,’ by Robert Reyes, SPE, Gerard Glasbergen, SPE, and Valerie Yeager, SPE, Halliburton, and Joseph Parrish, Occidental Petroleum, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed. Distributed-temperature sensing (DTS) is used in wells to determine the effectiveness of acid treatments. Concerns include where the acid was placed in the well, if the acid went where it was supposed to go, and if the acid went into the first least-resistive zone while subsequent zones went untreated. By use of DTS, it was determined that information seen at the surface can be misleading. Surface pressure can be masked by friction and is, therefore, not a valid indictor for what occurred downhole, and diversion can take place without surface indication. DTS enables practical real-time adjustment to the diversion strategy. Introduction As fluid flows in or out of the wellbore, it creates a characteristic thermal-gradient signature. DTS technology uses a fiber-optic cable to read temperature in real time, enabling validation of fluid placement. During production, reservoir fluid flows from the high-pressure reservoir into the low-pressure wellbore. Liquid recovery will result in a warming trend in the wellbore, while gas recovery will result in a cooling effect. These basic characteristics help determine liquid and gas movement. Effective fluid placement in the wellbore is critical for an optimized acid-treatment design. When determining fluid flow inside the wellbore, an understanding of the geothermal gradient and the internal Joule-Thomson effect is necessary. Fluid placement and zonal cover age are important for matrix-acidizing treatments, scale-inhibitor squeeze treatments, water-control treatments, water injection for enhanced recovery, and hydraulic-fracturing treatments. Case studies in this paper concentrate on matrix acidizing and production profiling. During these acid treatments, running a diverter involved the use of surface-pressure response, and the post-treatment-production improvement was used to determine if the treatment was effective. If effectiveness was questioned, design changes were tried, such as increasing or decreasing the rate, changing the percent of acid, and drop-ping diverters. Use of surface pressure to determine design changes for the current well and for the next well was not sufficiently accurate to make these determinations effectively. Fluid-friction pressures in the tubulars are not always known accurately, and they can affect the surface pressure, yielding erroneous bottomhole-pressure calculations. Case studies revealed that, during the diverter stages, the surface pressure might indicate diversion even though DTS data showed no diversion had occurred. Surface indicators falsely reported a downhole phenomenon because of fluid-friction pressure. In other case studies, the diverter was dropped and no surface indicators of effectiveness were detected. Again, downhole DTS data revealed the opposite: Diversion did occur.

Combining Distributed-Temperature Sensing With Inflow-Control Devices for Improved Injection Profile

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 127772, ’Combining Distributed-Temperature Sensing With Inflow-Control Devices Provides Improved Injection Profile With Real-Time Measurement in Power-Water Injector Wells,’ by Drew Hembling, and Garo Berberian, SPE, Saudi Aramco, and Mark Watson, Sam Simonian, and Garth Naldrett, SPE, Tendeka, prepared for the 2010 SPE Intelligent Energy Conference, Utrecht, The Netherlands, 23-25 March. Passive inflow-control devices (ICDs) are used to enhance the performance of horizontal producing wells in unfavorable environments such as nonuniform permeability and/or pressure variations along horizontal sections. ICDs were combined with a fiber-optic distributed-temperature-sensing (DTS) system to manage the water-injection profile across a reservoir horizon. This field trial demonstrated the effectiveness of the ICD system when used for injection-well profiling and for fluid diversion during acid stimulation. Introduction To understand the injection profile and well performance, a DTS system was deployed with ICDs and swellable packers as a field trial in a planned injection well. The objectives were to provide real-time information on multirate testing, determine real-time compartmental-injection profiling, and eliminate the need for horizontal flowmeter logging and well intervention. Recent designs use ICD-completion technology with a DTS umbilical deployed in the openhole producing section below a liner for real-time monitoring and controlling of inflow from each compartment, thereby extending well life and increasing recovery. This case involved the use of DTS and ICD technology to control injection profiles in an openhole near-horizontal well. Compartments were created by use of water-swellable packers with feedthrough capabilities for the DTS umbilical. Completion Design The reservoir section was separated into six compartments. On the basis of openhole-log analysis, the reservoir has a uniform porosity along the length of the well, with a few dolomite intervals present. The spacing of the ICDs and packers was planned in such a way as to isolate these dolomite sections while distributing the desired injection rate along the well. To mitigate the risk of getting stuck while running the lower completion to total depth, it was decided to limit the number of openhole packers to six, thereby reducing the number of allowable compartments. DTS System and Installation The DTS and a permanent downhole-monitoring system were installed in April 2009. The fiber-optic DTS cable was attached and secured to the production-tubing string and provides multipoint temperature profiles across the length of the well. The real-time data from the DTS system can be used for injection optimization and reservoir management by monitoring injection rates between and within the ICD compartments and by identifying crossflow conditions.

Identification of Steam-Breakthrough Intervals With DTS Technology

Summary Steam breakthrough in producing wells can be very problematic. Not only can production drop drastically, but catastrophic failure events can occur; holes can be cut in tubulars, screens, and casing. Many of these events can result in loss of the borehole. Therefore, it is critical that the offending sand zone is identified quickly. Many breakthrough-identification methods have been tried, including produced-well temperature, pulsed-neutron logging, and drilling observation wells to monitor zonal temperatures. This paper discusses methods for installing optical fibers in oil and gas wells for distributed temperature sensing (DTS), the search to gain the considerable value offered by fiber-optic technology, and the development of an extremely cost-effective and accurate method that takes advantage of the power of DTS technology for determining steam breakthrough in producing wells.