Development and Application of Fiber-Optic Sensing Technology for Monitoring Soil Moisture Field

Accurate acquisition of the moisture field distribution in in situ soil is of great significance to prevent geological disasters and protect the soil ecological environment. In recent years, rapidly developed fiber-optic sensing technology has shown outstanding advantages, such as distributed measurement, long-distance monitoring, and good durability, which provides a new technical means for soil moisture field monitoring. After several years of technical research, the authors’ group has made a number of new achievements in the development of fiber-optic sensing technology for the soil moisture field, that is, two new fiber-optic sensing technologies for soil moisture content, including the actively heated fiber Bragg grating (AH-FBG) technology and the actively heated distributed temperature sensing (AH-DTS) technology, and a new fiber-optic sensing technology for soil pore gas humidity are developed. This paper systematically summarizes the three fiber-optic sensing technologies for soil moisture field, including sensing principle, sensor development and calibration test. Moreover, the practical application cases of three fiber-optic sensing technologies are introduced. Finally, the development trend of fiber-optic sensing technology for soil moisture field in the future is summarized and prospected.

The First Behind-Casing Fiber-Optic Installation in a High-Pressure High-Temperature Deep Gas Well in Oman

This paper discusses the first fiber-optic (FO) installation in a vertical high-pressure high-temperature deep gas well in PDO, Oman. A specially designed fiber-optic cable was successfully installed and cemented behind the production casing, which was subsequently perforated in an oriented manner without damaging the cable. This paper also describes how the fiber-optic cable was used afterwards to acquire Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) data for the purpose of hydraulic fracturing diagnostics. Fiber-optic surveillance is becoming an increasingly important activity for well and reservoir surveillance. The added complexity of the fiber-optic installation will affect the well design, which is one of the elements that requires focused attention, especially when the fiber is installed behind casing. The impact on casing design, wellhead design, perforation strategy, and logging requirements will all be discussed. In order for a well to be completed with a permanent fiber-optic cable, a few critical procedures need to be followed, including: –modifying the wellhead design to include feedthrough ports for the cable;–optimizing the cement design;–imposing strict procedures to ensure the cable is installed behind the casing without getting stuck;–changing the perforation phasing to avoid damaging the cable;–mapping the location of the cable to allow the gun string to be oriented away from the cable. The fiber-optic cable itself needed to be designed to be protected in such a way that it would not be damaged during installation and completion (perf/frac) activities. Furthermore, the cable was also optimized to improve its detectability, to aid the oriented perforation. In deep gas wells, much more than in conventional shallow water injectors or oil producers, the well integrity aspect should be given special attention. Specifically, any risks related to unwanted gas leaks, either through the control line, poor cement, or because of other design errors should be avoided. In deep gas wells, high temperature and pressure will also play a big role in the expected lifespan of the cable. Finally, the well was hydraulically fractured in four stages, using the "plug-and-perf" technique, during which DAS and DTS data were acquired continuously and across all depths of the well. The data provided valuable information on the effectiveness of each of the frac stages, it could be used to analyze screen-outs and detect out-of-zone injection, and recommendations for the optimizations of future hydraulic frac designs could be derived. The fiber-optic data were also integrated with other open-hole data for improved understanding of the reservoir performance. The next step will be to acquire repeated time-lapse DAS and DTS data for production profiling, to gain more insights of how the long-term production performance is affected by the hydraulic frac operations.

Investigating Taylor’s frozen turbulence hypothesis in the surface layer at an ideal desert field site using fibre-optic distributed temperature sensing

<p>Taylor’s frozen turbulence hypothesis is the most critical assumption through which time-resolving sensors may be used to derive statistics of the turbulent spatial field. Namely, it relates temporal autocorrelation to spatial correlation via the mean wind speed and is invoked in almost all boundary layer field work. Nevertheless, the conditions and scales over which Taylor’s hypothesis is valid remain poorly understood in the atmospheric boundary layer.</p> <p>As part of the Namib Turbulence Experiment (NamTEX) campaign in March 2020, a pseudo-3D fibre-optic distributed temperature sensing (DTS) array was installed within a 300 x 300 m area in the Namib desert. The array is X-shaped in plan view and contains 16 measurement heights from 0.45 m to 2.85 m. Fibre-optic sensing provides air temperature measurements at unprecedented spatio-temporal density (0.25 m horizontally, 0.17 m vertically, and 1 Hz) and was coupled with a vertical array of traditional sonic anemometer point measurements to investigate the relationship between spatial and temporal temperature fields. The Namib provides an ideal location for fundamental boundary layer research: homogenous flat surfaces, no vegetation, little moisture, strong solar forcing, regular and repeated clear-sky conditions, and a wide range of atmospheric stabilities.</p> <p>Using the NamTEX DTS array we present the first field investigation of Taylor’s hypothesis that considers boundary layer stability and is independent of wind direction. A novel method of 2d horizontal cross-correlation between all possible points of a single height of the DTS is employed to produce spatial ‘maps’ of the turbulent flow, whose velocity, direction, and size may be tracked through time.</p>

Well Integrity Leak Diagnostic Using Fiber-Optic Distributed Temperature Sensing and Production Logging

Fiber optics has many applications in the oil and gas industry. In recent years, fiber optics has found usefulness in leak detection. The leaks can be efficiently identified using fiber-optic distributed temperature sensing measurement, thereby mitigating the health, safety, and environmental (HSE) risk associated with well integrity. Further, a production log can be used to gain more insight and finalize a way ahead to resolve well integrity issues. An innovative solution-driven approach was defined, with fiber-optic distributed measurement playing a key role. Multiple leaks were suspected in the well completion, and a fiber-optic cable was run to identify possible areas of the leak path. After the fiber-optic data acquisition, a production log was recorded across selective depths to provide an insight on leak paths. After identifying leak depths, a definitive decision between tubular patching and production system overhaul was decided based on combined outputs of the fiber-optic acquisition and production log. Results are presented for a well where multiple leaks were successfully identified using the novel operational approach. Further, operational time was reduced from 3 days (conventional slickline memory or e-line logging performed during daylight operation) to 1 day (a combination of fiber-optic distributed temperature sensing and production log in a single run). The diagnosis of production system issues was completed in one shut-in and one flowing condition, thereby reducing the risk of HSE exposure with multiple flowing conditions (to simulate the leak while the conventional production logging tool is moved to different depths in the well). Additional insight on leak quantification was confirmed from the production log data, where one leak was noted at the tubing collar while the other leak was noted a few meters above the tubing collar. This observation was substantial in deciding whether to proceed with tubing patch or replace the entire production tubing. The novel operational approach affirms fiber-optic distributed temperature measurement's versatility in solving critical issues of operation time and reducing HSE exposure while delivering decisive information on production system issues. The paper serves as a staging area for other applications of similar nature to unlock even wider horizons for distributed temperature sensing measurement.

Water Injection Profiling Using Fiber Optic Sensing by Applying the Novel Pressure Rate Temperature Transient PTRA Analysis

Fiber Optic Systems, such as Distributed Temperature Sensing (DTS), have been used for wellbore surveillance for more than two decades. One of the traditional applications of DTS is injectivity profiling, both for hydraulically fractured and non-fractured wells. There is a long history of determining injectivity profiles using temperature profiles, usually by analyzing warm-back data with largely pure heat conduction models or by employing a so-called "hot-slug" approach that requires tracking of a temperature transient that arises at the onset of injection. In many of these attempts there is no analysis performed for the key influencing physical factors that could create significant ambiguity in the interpretation results. Among such factors we will consider in detail is the possible impact of cross-flow during the early warm-back stage, but also the temperature transient signal that is related to the location of the fiber-optic sensing cable behind the casing when the fast transient data are used for interpretation such as the "hot slug" during re-injection. In this paper it will be shown that despite all such potential complications, the high frequency and quality of the transient data that can be obtained from a continuous DTS measurement allow for a highly reliable and robust evaluation of the injectivity profile. The well-known challenge of the ambiguity of the interpretation, produced by the interpretation methods that are conventionally used, is overcome using the innovative "Pressure Rate Temperature Transient Analysis" method that takes maximum use of the complete DTS transient data set and all other available data at the level of the model-based interpretation. This method is based on conversion of field measurements into injectivity profiles taking into account the uncertainty in different parts of the data set, which includes the specifics of the DTS deployment, the uncertainty in surface flow rates, and possible data gaps in the history of the well. Several case studies will be discussed where this approach was applied to water injection wells. For the analysis, the re-injection and warmback DTS transient temperature measurements were taken from across the sandface. Furthermore, for comparison, injection profiles were also recorded by conventional PLTs in parallel. This case study will focus mostly on the advanced interpretation opportunities and the challenges related to crossflow through the wellbore during the warm-back phase, related to reservoir pressure dynamics, and finally related to the impact of the method of DTS deployment. In addition to describing the interpretation methodology, this paper will also show the final comparison of the fiber-optic evaluation with the interpretation obtained from the reference PLTs.

New Perspectives for Acidizing Tight Carbonate Oil Producers Completed Across an Extended Openhole Horizontal Section

Over the past decade, coiled tubing (CT) has been one of the preferred fluid conveyance techniques in tight carbonate oil producers completed with an uncased horizontal section. In the onshore Middle East, conventional CT stimulation practices have delivered inconsistent results in that work environment. This is mainly due to a mix of reservoir heterogeneity, limited CT reach, lower CT pumping rates, uncontrolled fluid placement, and uncertainty of downhole dynamics during the stimulation operations. An intervention workflow recently validated in onshore Middle East to acidize tight carbonate openhole horizontal water injectors was introduced for the first time in an oil producer. The advanced stimulation methodology relies on CT equipped with fiber optics to visualize original fluid coverage across the openhole interval through distributed temperature sensing (DTS). Real-time downhole telemetry is used to control actuation of CT toolstring components and to understand changing downhole conditions. Based on the prestimulation DTS survey, the open hole is segmented into sections requiring different levels of stimulation, fluid placement techniques, and diversion requirements. The candidate carbonate oil producer featured an average permeability of 1.5 md along 8,003 ft of 6-in. uncased horizontal section. Because of the horizontal drain's extended length and the presence of a minimum restriction of 2.365-in in the 3 1/2-in. production tubing, a newly developed CT slim tractor was essential to overcome reach limitations. In addition, a customized drop-ball high-pressure jetting nozzle was coupled to the extended reach assembly to enable high-energy, pinpoint acidizing in the same run. The instrumented CT was initially run until lockup depth, covering only 53% of the horizontal section. The CT slim tractor was then precisely controlled by leveraging real-time downhole force readings, enabling full reach across the open hole. Prestimulation DTS allowed identification of high- and low-intake zones, which enabled informed adjustments of the acidizing schedule, and in particular the level of jetting required in each section. After its actuation via drop-ball, the high-pressure jetting nozzle was operated using downhole pressure readings to ensure optimum jetting conditions and avoid exceeding the fracturing threshold. Upon completion of the stimulation stage, post-stimulation DTS provided an evaluation of the fluid placement effectiveness. After several weeks of production, the oil rate still exceeded the operator's expectations fivefold. This intervention validates the applicability of the advanced matrix stimulation workflow in tight carbonate oil producers completed across a long openhole horizontal interval. It also confirms the value of real-time downhole telemetry for optimal operation of extended reach toolstrings and the understanding of the downhole dynamics throughout stimulation treatments, the combination of which ultimately delivers breakthrough production improvements compared to conventional stimulation approaches, in a sustainable manner.

Single-Phase Retarded Inorganic Acid Optimizes Remediation of Drilling Formation Damage in High-Temperature Openhole Horizontal Carbonate Producer

In high-temperature carbonate producers, conventional hydrochloric (HCl) acid systems have been ineffective at delivering sustainable production improvement due to their kinetics. Retarded acids are deemed necessary to control the reaction and create effective wormholes. This scenario is even more critical in wells completed across long openhole horizontal intervals due to reservoir heterogeneity, changing downhole dynamics, and uniform acid placement goals. Out of the different retarded acid options, emulsified acid is one of the preferred choices by Middle East operators because of its excellent corrosion inhibition and deep wormhole penetration properties. However, it also brings other operational complexities, such as higher friction pressures, reduced pump rates, and more elaborate mixing procedures, which in some cases restrict its applicability. The recent introduction of a single-phase retarded inorganic acid system (SPRIAS) has enabled stimulation with the same benefits as emulsified acids while eliminating its drawbacks, allowing friction pressures like that of straight HCl and wormholing performance equivalent to that of emulsified acid. A newly drilled oil producer in one of the largest carbonate fields in onshore Middle East was selected by the operator for pilot implementation of the SPRIAS as an alternative to emulsified acid. The candidate well featured significant damage associated with drilling, severely affecting its productivity. The well was completed across 3,067 ft of 6-in. openhole horizontal section, with a bottomhole temperature of 285°F, permeability range of 0.5 to 1.0 md, and an average porosity of 15%. Coiled tubing (CT) equipped with fiber optics was selected as the fluid conveyance method due to its capacity to enable visualization of the original fluid coverage through distributed temperature sensing (DTS), thus allowing informed adjustment of the stimulation schedule as well as identification of chemical diversion and complementary fluid placement requirements. Likewise, lower CT friction pressures from SPRIAS enabled the utilization of high-pressure jetting nozzle for enhanced acid placement, which was nearly impossible with emulsified acid. Following the acidizing treatment, post-stimulation DTS showed a more uniform intake profile across the uncased section; during well testing operations, the oil production doubled, exceeding the initial expectations. The SPRIAS allowed a 40% reduction in CT friction pressures compared to emulsified acid, 20% optimization in stimulation fluids volume, and reduced mixing time by 18 hours. The experience gained with this pilot well confirmed the SPRIAS as a reliable option to replace emulsified acids in the region. In addition to production enhancement, this novel fluid simplified logistics by eliminating diesel transportation, thus reducing equipment and environmental footprints. It also reduces friction, thus enabling high-pressure jetting via CT, leading to more efficient stimulation with lower volumes.

Distinguishing Time Scales of Katabatic Flow in Complex Terrain

To examine spatial and temporal scales of katabatic flow, a distributed temperature sensing (DTS) optical fiber was deployed 2 km down a mild slope irregularly interrupted by small-scale drainage features as part of the Mountain Terrain Atmospheric Modeling and Observation (MATERHORN) experiment conducted at the U.S. Army Dugway Proving Ground, Utah. The fiber was suspended at two heights near the surface, enabling measurement of variations in lapse rate near the surface at meter-scale spatial resolution with 1-min temporal resolution. Experimental results derived from the DTS and tower-mounted instrumentation indicate that airflow through small-scale drainage features regulated the local cooling rate whereas topographic slope and distance along the drainage strongly influenced the larger-scale cooling rate. Empirical results indicate that local cooling rate decays exponentially after local sunset and basin-wide cooling rate decreases linearly with time. The difference in the functional form for cooling rate between local and basin-wide scales suggests that small-scale features have faster timescales that manifests most strongly shortly after local sunset. More generally, partitioning drainage flow by scale provides insight and a methodology for improved understanding of drainage flow in complex terrain.