Integrated Analysis Combining Microseismic Mapping and Fiber-Optic Distributed Temperature Sensing (DTS)

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.

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 article discusses key considerations in the practical application of data analysis using distributed temperature sensing (DTS) technology. Conventional temperature logging techniques provide temperature data only during specific surveys and can significantly interfere with normal well operations. Application of DTS technology has made it possible to overcome many of the limitations and problems of thermal studies and makes it possible to obtain temperature measurements along the wellbore at short intervals without changing the well operating mode. It is demonstrated that in deviated and horizontal wells, discrepancies between the DTS measured depth (MD/ML) and the actual wellbore depth (i.e., the difference between the optical fiber length and the well path) vary across different intervals due to uneven fiber tension. These discrepancies are typically more pronounced in inclined and horizontal sections compared to vertical ones and must be accounted for when interpreting temperature variations along the wellbore. To correct this technical inaccuracy, DTS data should be calibrated against conventional well logging results. The study also identifies random temperature fluctuations inherent in DTS measurements, which can influence the accuracy of the recorded values. These signal noises are also observed when the well is shut in. Based on the statistical analysis, the closeness of the distribution of DTS measurement noise when the well is shut in to the normal distribution is shown. To determine the optimal sampling interval and the minimum number of measurements required for reliable temperature profiling, a comparative analysis with data from permanent downhole temperature gauges is recommended. Keywords: well integrity; monitoring; temperature profiling; distributed temperature sensing (DTS); signal noise; thermal fluctuation; distributed sensing.

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.

Reservoir performance monitoring can provide real-time information that can enable more timely operational decisions to be made. Often, the data can be collected without performing an intervention. This paper will discuss one of the newest reservoir monitoring techniques — fiber-optic distributed temperature sensing or DTS and some of the recent successes provided by DTS that are enabling it to be considered as an integral service for reservoir monitoring.DTS can provide a temperature profile of the entire wellbore in real time, which in turn, can provide an enhanced understanding of the downhole flow (or injection) profile. Historically, DTS has been a niche service for steamflood and geothermal applications due to its high bottomhole temperature (BHT) survivability. Acceptance of the technology, deployments costs, and value added are the reasons applications outside of steamflood and geothermal wells are being recognized.This paper presents three cases of non-steamflood applications of DTS. All three cases are from an oilfield in north-central Sumatra, Indonesia. Each illustrates how the use of DTS optimized the completion and/or improved the well/reservoir management strategies. The three cases provided the following services: Determined fluid level for electrical submersible pump (ESP) optimization.Monitored realtime fracture-height growth during a mini-frac treatment.Flow profiled in an artificial lift completion where the producing interval was inaccessible for a conventional production logging test (PLT).

<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>

One of the most important performance indicators of a fiber optic distributed temperature sensing (DTS) system is its operational stability, which depends on the performance of each device making up the system. Such individual device performance itself is affected by temperature and other environmental conditions. As a result, ambient fluctuations invariably lead to measurement uncertainties and drifts, seriously degrading the system performance. To ameliorate such adverse effects of the environment, we propose a dynamic sampling-correction scheme, which we have implemented on our fiber optic Raman DTS system, resulting in an average temperature error within 1°C when the main chassis undergoes a temperature variation over the range -25°C-45°C. The drastically improved system stability foreshadows better performance and reliability in engineering applications.

As steam-assisted gravity drainage (SAGD) producers continue to look for methods for enhancing oil recovery, understanding the dynamics at play in the evolution of the steam chambers becomes critical. Steam thief zones introduce operational risks affecting the economic recovery of the bitumen. Sensitive reservoirs need careful monitoring to avoid compromising cap rock integrity and to detect steam breakthrough. A need exists for real-time, spatially sensitive temperature monitoring in production, injection, and observation wells. Although such monitoring has been used in production and injection wells for decades, operators of SAGD observation wells (with typical two to six per pad) mostly used either piezometers for single-point pressure and temperature measurements and/or multiple-point thermocouple bundles. Distributed temperature sensing (DTS) application in these remote environments has been limited by availability of infrastructure with temperature-controlled environment and power supply in close proximity to the wellhead, which most DTS interrogation equipment requires. In this paper we introduce and demonstrate the installation of a new stand-alone, low-power DTS solution to address the specific needs of remote observation wells within a northern Alberta SAGD field. An acquisition system with extended working temperature range and small geometry form is installed within enclosures equipped with temperature-control devices and zonal certification. Downhole temperature data is transmitted continuously over a cellular network to a secure server with data-trending software for ease of viewing. The system was installed in February 2015 and the downhole temperature data accessible through web browser download during the field trial period.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194284, “Pushing the Limits of Damage Identification With Coiled Tubing in Extreme Conditions: A Success Story From Japan,” by Nozomu Yoshida, SPE, Satoshi Teshima, SPE, and Ryo Yamada, INPEX, and Umut Aybar, SPE, and Pierre Ramondenc, SPE, Schlumberger, prepared for the 2019 SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 26–27 March. The paper was peer reviewed and is scheduled for publication in SPE Production &amp; Operations. The success of water-conformance operations often depends on clear identification of the water-production mechanism. Such assessment can be complicated significantly when formation damage is also occurring. Coiled tubing (CT) and distributed temperature sensing (DTS) were combined to overcome challenging conditions (high temperature, low injectivity, high deviation, long perforated intervals, and wellbore damage) to identify damaged oil zones and suspected water-bearing zones in an onshore well in Japan. Introduction Source and location affect the selection of water-shutoff techniques, which are either mechanical or chemical in nature or a combination. No matter the operational approach, identification of the water zone is a critical step for any subsequent course of actions. One method for the identification of water-producing zones is the use of production logging. Conventional production logging uses spinners and capacitance logs to detect water flow in the wellbore. Production logging tools (PLTs) can be deployed into the wellbore using slickline, wireline, or CT. To enable real-time evaluation of the acquired data, possible options include wireline, digital slickline, and CT equipped with either a conductor cable or fiber optics. In damaged wells with high water cut, flow conditions can be unstable, with drastic changes in flow regimes. Once the well can no longer sustain stable flow because of reservoir depletion or damage in the absence of an artificial-lift method, a PLT becomes impractical. Furthermore, when wellbore conditions are complicated by the presence of debris or contaminants, data acquisition itself becomes difficult. Quantification of the damage profile and of water-producing intervals is of great importance in proper planning for subsequent operations. To address these challenges, an alternative approach was used wherein DTS obtained through fiber optics deployed with CT was used to quantify damage profiles in severely damaged wells and to identify suspected water-bearing zones by integrating complementary information. The proposed operational procedures are similar to those used for the quantification of fluid placement during acidizing operations: injection of fluid to cool down the formation and shut-in to measure rate and amplitude of temperature recovery along intervals of interest. In the present case, brine was used as the injection fluid. Quantification of the damage and injection-rate profiles are achieved by temperature inversion; the measured DTS data are matched with the simulated temperature response given by combined flow and thermal numerical models accounting for key formation and near-wellbore parameters. The subject well was suspected to be severely damaged during the completion phase and yielded a relatively high water cut during flow test. This case not only highlights the validity of the proposed approach but also details the work flow and analyses performed to obtain meaningful data and to reduce uncertainty of the interpretation. The work also raises the importance of the integration of complementary data for a comprehensive understanding of well conditions.

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.

The world's largest steam-flood operation is conducted on the island of Sumatra in Indonesia. Fiber-optic Distributed Temperature Sensing (DTS) surveys are used in the Sumatra fields to provide valuable data for reservoir management. The DTS profile data can determine the temperature and extent of a steam chest as well as the temperature gradient for either over-burden- or under-burden reservoirs. This information is vital for properly setting steam-injection target rates. The information is also used to mitigate steam breakthroughs and eruptions as well as to identify bypass oil. Steam flood operations experience many types of problems: i.e., inefficient injection rates, wasted heat to the casing, sanding in producers, liner failures, pump failures as wells as the need to improve the efficiencies of the vapor collection systems, well-test stations, and central gathering stations. Based on these challenging problems, periodic wellbore temperature surveys are required in order to improve heat management and ultimately improve profitability. Conventional temperature logs cannot be run in these wells without first pulling the pumps from the completion. Therefore, employing a fiber-optic DTS system that would be attached to the production tubing was suggested. This paper will present case histories of successful applications of fiber-optic DTS surveys that improved steam- flood management in this steam- flood field in Indonesia. The benefits from the fiber-optic DTS monitoring were: Significant improvement in the understanding of steam breakthrough zones along the pay zone interval of production wellsImproved understanding of the steam path in steam-injector wellsImprovement in the real-time temperature profile in observation wells to identify steam-zone development and unswept or bypassed oil zones in the steam flood patterns.

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 102801, "Imaging Seismic Deformation Induced by Hydraulic-Fracture Complexity," by S.C. Maxwell, SPE, C.K. Waltman, SPE, N.R. Warpinski, SPE, M.J. Mayerhofer, SPE, and N. Boroumand, Pinnacle Technologies, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24– 27 September. Microseismic mapping is used extensively in the Barnett shale to map hydraulic-fracture complexity associated with interactions of the stimulation with pre-existing fractures. Previous studies have indicated a fair correlation between well performance and extent of the seismically active volume. In the full-length paper, the density of the total seismic moment release is used as an indication of the seismic deformation that may correlate to fracture density. Incorporating seismic-moment density with stimulated reservoir volume (SRV) improved correlation with well production. Introduction Microseismic mapping of hydraulic-fracture stimulations has become a common technique used to map fracture growth and geometry. Microseismic images provide details of fracture azimuth, height, length, and complexity resulting from interaction with pre-existing fractures. The resulting images can be used to calibrate numerical simulations of fracture growth, allowing more-confident modeling of other stimulations in the field and identification of the stimulated region that may be drained by the well. Microseismic mapping in the Barnett shale has demonstrated repeatedly extreme fracture complexity resulting from interaction between the injection and a pre-existing fracture network. The Barnett shale has very low intrinsic matrix permeability, and the permeability enhancement associated with the fracture stimulation results in permeable fracture networks sufficient for economic gas recovery. Previous studies have shown a correlation between the SRV, as measured by the volume of the reservoir that emits microseisms during the stimulation, and the production ultimately realized from the well. The correlation is attributed to larger fracture networks being stimulated in wells where a large microseismically active volume of the reservoir has been realized, resulting in more permeable fracture pathways connected to the well and hence a higher potential for gas flow to the well. Recently, many operators in the Barnett shale have attempted horizontal completions, which have enabled large volumes of the reservoir to be stimulated with large fracture networks. Many of these completions use perforated, cemented liners, and the microseismic images allow identification of improved perforation staging to maximize the SRV. Beyond the basic hypocentral locations of the microseisms used to calculate the SRV, additional seismic-signal characteristics allow investigation of the source of the mechanical deformation resulting in the microseisms. In particular, the seismic moment, a robust measure of the strength of an earthquake or microearthquake, can be used to quantify the seismic deformation.

The use of fiber optic distributed temperature sensing (DTS) to detect and locate leaks is still in its infancy in water infrastructure, despite its promising capabilities. Only few experiments tested this technology, and none of these studies focused on small but persistent leaks, like background leakages, which are ubiquitous and generally go undetected with the technology currently available, thus posing a serious threat to the available water resource. To test the feasibility of detecting and locating background leakages with fiber optic DTS, this study provides a detailed analysis on flow and temperature alterations around leaking water pipelines in presence of small leaks (5, 25, and 125 L/d) with small to moderate temperature differences with the surrounding soil, under 3 different pipe defect configurations, either in absence or in presence of pipe thermal insulation. Transient 3D heat transfer-unsaturated flow numerical simulations showed that there is potential to use temperature alterations to detect and locate incredibly small leaks with fiber optic DTS, like background leakages, despite the influence of pipe temperature on the surrounding soil. The analysis showed that extent, distribution, and magnitude of these alterations are convection dominated at a given temperature difference between leaked water and undisturbed soil, and that it may not be strictly necessary to place the optical fiber directly below the pipe. Indeed, optical fibers located within the utility trench at the sides of the pipe and below its bottom showed comparable or even better performance, thus giving new opportunities to retrofit existing pipelines as well.

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.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 187441, “Improved Monitoring System for Heavy-Oil Steam-Assisted-Gravity-Drainage Wells,” by Christopher Baldwin, Weatherford, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8–11 October. The paper has not been peer reviewed. The complete paper provides an overview of the development of fiber-optic sensing for steam-assisted-gravity-drainage (SAGD) applications, including a review of more than 10 years of work in development and field applications in western Canada. Information provided in this paper is applicable beyond SAGD applications. The fiber-optic monitoring systems might also be used for intelligent, subsea, and unconventional wells. Introduction One area that has benefited from the unique advantages of fiber-optic sensing is thermal monitoring of SAGD wells. One particular fiber-optic technology that has proved successful in these thermal-monitoring applications is wavelength-domain multiplexing of Bragg-grating-based fiber-optic sensors. Commonly referred to as array temperature sensing (ATS), the Bragg-grating arrays can be manufactured splice-free for long-term reliability. The number of thermal sensing points can range from a few to well over 100 for a single cable. Each Bragg-grating sensing point provides a real-time, accurate measurement of temperature at that location along the wellbore. ATS systems have been used successfully to monitor the steam-injection and production processes in SAGD wells. ATS systems are capable of performing more-accurate temperature measurements and are able to resolve much smaller temperature features compared with distributed temperature sensing (DTS). Bragg-grating optical sensors not only provide temperature measurements but also can be packaged in a transducer to provide pressure and temperature (PT) also can be packaged in a transducer to provide pressure and temperature (PT) readings. The optical PT gauge is compatible with the surface instrumentation that records the ATS responses, allowing for the PT gauge to be integrated at the end of the ATS optical fiber for single-wellhead penetration, providing multiplexed DTS and PT measurements. Environmental Effects on Downhole Fiber-Optic Sensors The requirements for a successful monitoring system in SAGD applications are dictated by the harsh environments experienced downhole. In the past, the presence of hydrogen in these applications has caused issues with various fiber-optic sensing technologies. Improvements in optical-fiber design and downhole cable construction have helped to mitigate some of these issues, but any downhole monitoring system must be able to cope with the presence of hydrogen in relatively high-temperature environments.