I. Introduction Fiber optic sensing technology is a novel sensing technology that rapidly developed in the 1970s alongside the advancement of fiber optic communication technology. Developed countries abroad have achieved significant results in the application research of fiber optic sensing technology, and many fiber optic sensing systems have been put into practical use, becoming commercial alternatives to traditional sensors. In the development of oil fields, detailed information on the properties and state of fluids within the well during production or water injection is needed. This requires oil well logging, whose reliability and accuracy are crucial. Traditional electronic sensors cannot operate in harsh downhole environments such as high temperature, high pressure, corrosion, and geomagnetic and geoelectric interference. Fiber optic sensors overcome these difficulties. They are insensitive to electromagnetic interference and can withstand extreme conditions, including high temperature, high pressure (tens of megapascals and above), and strong impacts and vibrations. They can measure wellbore and well site environmental parameters with high precision. Furthermore, fiber optic sensors have distributed measurement capabilities, allowing them to measure the spatial distribution of the measured quantity and provide profile information. Moreover, fiber optic sensors have a small cross-sectional area and short shape, occupying minimal space within the wellbore. Fiber optic sensors have made significant progress in the field of geophysical logging. Major oil production companies, logging service companies, and various fiber optic sensor R&D institutions and enterprises worldwide have participated in the research and development process. In order to expand the application fields of fiber optic sensors, this paper reviews the research and progress of fiber optic sensors in the field of geophysical logging, hoping that its research can contribute to further improving the level of oil development. II. Research Progress of Fiber Optic Sensors in Logging 1. Reservoir Parameter Monitoring (1) Pressure Monitoring Due to the needs of the development plan, the management of reservoir pressure needs to be particularly careful. The purpose of this is to reduce the crude oil loss caused by mining under pressure below the bubble point and to reduce the crude oil loss caused by the overpressure of the reservoir squeezing the crude oil into the aquifer during gas injection. The sensors used for traditional downhole pressure monitoring are mainly strain gauges and quartz crystal gauges. Strain gauges are affected by temperature and hysteresis, while quartz gauges are affected by rapid changes in temperature and pressure. In pressure monitoring, these sensors also involve problems such as difficult installation and poor long-term stability. Downhole fiber optic sensors offer advantages such as the absence of downhole electronic circuitry, ease of installation, small size, and strong anti-interference capabilities—all essential for downhole monitoring. CiDRA, a US company, is at the forefront of fiber optic pressure monitoring research. Their researchers have discovered the linear pressure response of Bragg fiber grating sensors. Developed sensors can operate up to 175 °C, with products under development for 200 °C and slightly higher temperatures; 250 °C is the next target. Pressure measurement errors at different temperatures and pressures are less than ±6.89 kPa within the test range (0 MPa to 34.5 MPa), equivalent to the best performance of electronic measurement systems. Currently, CiDRA's fiber optic pressure sensors have the following specifications: measurement range 0–103 MPa, overpressure limit 129 MPa, accuracy ±41.3 kPa, resolution 2.06 kPa, long-term stability ±34.5 kPa/yr (continuously maintained at 150 °C), and operating temperature range 25 °C to 175 °C. In 1999, the company conducted a test of its pressure monitoring system in the Baker oil field in California. The results showed that the system had very high accuracy and has now been delivered for commercial sale. In 2001, the company's pressure sensor was installed in several BP wells in the UK to monitor stress changes, and the results showed that it had sufficient reliability. Tsutomu Yamate et al. of the Doll Research Center of Schlumberger Oilfield Services in the United States have conducted long-term research on downhole monitoring using Bragg fiber grating sensors. They developed a side-hole Bragg fiber grating sensor that is insensitive to temperature. The maximum operating temperature is 300 °C and the maximum measuring pressure is 82 MPa. At the maximum measuring pressure, the sensitivity to temperature is extremely small, which can be used for downhole pressure monitoring. (2) Temperature monitoring Distributed fiber optic temperature sensors have the potential to provide a new way to monitor production and reservoirs by continuously collecting temperature data along the entire completion length. Because the changes in the temperature profile of the well can be compared with other surface data (flow rate, water cut, wellhead pressure, etc.) and open-hole logging curves, the operator can be provided with qualitative and quantitative information about the changes that occur downhole. Traditional temperature measurement tools can only measure the temperature at a single point within a given timeframe. To test the entire temperature range, point sensors must move back and forth within the well, inevitably affecting the well's environmental equilibrium. The advantage of fiber optic distributed temperature sensors is that the fiber does not need to move within the detection area, ensuring the well's temperature equilibrium remains unaffected. Furthermore, since the fiber is housed within a capillary tube, fiber optic distributed temperature sensor testing can be performed wherever the capillary tube can reach. One of the most widely used fiber optic sensors in downhole monitoring applications is the Raman backscatter distributed temperature detector, a method that has been widely applied in measuring wellbore temperature profiles (especially in steam-driven wells). Distributed temperature sensors require consideration of the number of measurement points and connector attenuation. The problems and solutions encountered include: a) Signal attenuation due to fiber optics and connectors, addressed by minimizing the number of connectors, using Bragg fiber grating sensors, and improving connector performance; b) Risk of damage during downhole installation, addressed by employing skilled workers, requiring an external protective layer for the fiber optic sensor, and reducing stress (including stress caused by perforation and temperature). For fiber optic distributed temperature sensor systems, Sensa in the UK has always been at the forefront of technology, with a series of products on the market. It has also cooperated with major oil companies to actively explore the application of fiber optic distributed temperature sensors in oil wells. CiDRA has also been researching fiber optic temperature sensors. Currently, the technical specifications of the company's temperature sensors are: measurement range 0℃～175℃, accuracy ±1℃, resolution 0.1℃, and long-term stability ±1℃/yr (continuous use at 150℃). One of the main drawbacks of current fiber optic temperature and pressure sensors is the cross-sensitivity of temperature and pressure. How to eliminate or utilize this cross-sensitivity is a hot research topic. (3) Multiphase flow monitoring In order to do a good job in reservoir monitoring and oilfield management, the most critical link is to obtain a stable and reliable total flow profile and the holdup of each phase fluid in production wells and injection wells. However, most oil wells are developed in layers, each with different water content and sometimes large flow velocities, which brings great difficulties to measuring and analyzing the production status of oil wells using conventional production logging equipment. The frictional resistance of liquids in tubing and the jetting from the reservoir into the wellbore make differential pressure density instruments inaccurate, and electronic probes are unable to detect small oil bubbles in the liquid. There are two methods for measuring multiphase flow using fiber optics. The first is the gas holdup fiber optic sensor from Schlumberger, which can directly measure the gas holdup in multiphase flow. Its four fiber optic probes are evenly distributed across the cross-section of the wellbore, and their spatial orientation can be accurately measured using an integrated relative orientation sensor. In the gas-liquid mixture, the gas holdup and foam quantity (both correlated with gas flow rate) are determined by the light signals reflected from the probes. Furthermore, the measurements from each probe are used to create a picture of the gas flow in the well. This picture data is particularly suitable for deviated and horizontal wells, providing a better understanding of multiphase flow patterns and interpreting the inherent phase separation of these patterns under inclined conditions. Recently, this instrument has been successfully tested in well logging experiments worldwide. The data it provides can directly determine and quantify gas and liquid in multiphase mixtures, accurately diagnose wellbore problems, and aid in production adjustments. The instrument has passed field tests in three wells. The second method involves determining the phase composition of a two-phase mixture by measuring sound velocity. This is because the sound velocity of the mixed fluid is correlated with the sound velocity and density of each individual phase fluid, a correlation common in two-phase gas/liquid and liquid/liquid mixtures, and also applicable to multiphase mixtures. Determining the volume fraction of each phase based on the sound velocity of the mixed fluid involves measuring the volume fraction of each individual phase flowing through the flowmeter (i.e., holdup measurement). Whether the holdup of a particular fluid phase equals its flow volume fraction depends on whether that phase exhibits severe slippage relative to other phases. For oil-water two-phase mixtures without severe slippage, a uniform flow model can be used for analysis; however, for flow states with severe slippage, a more sophisticated slippage model must be applied to interpret the flowmeter data to accurately determine the flow rate of each phase. Flow circulation experiments have shown that for oil-water mixtures, long-wavelength sound velocity measurements from the flowmeter can determine the volume fraction of each phase (i.e., holdup), unaffected by flow heterogeneity (such as laminar flow). CiDRA has leveraged the inherent advantages of fiber optic sensors to develop a downhole optical multiphase flow sensor. Current samples are limited to measuring quasi-homogeneous fluids, such as two-phase (oil and water) or three-phase (oil, water, and gas) with a gas volume fraction of less than 20%. To investigate the performance of this novel fiber optic multiphase flow sensor in measuring oil/water/gas three-phase flow in production wells, CiDRA recently conducted experiments in a test well. The test well contained a mixture of oil with a viscosity of 32 API, water with 7% salinity, and mine natural gas (methane). The test temperature was 100°F, and the pressure was <2.75 MPa. Within the 0%–100% water cut range, the instrument's measurement error was less than ±5%, meeting the accuracy requirements. The flowmeter can determine the water holdup in crude oil and brine mixtures with an error within ±5% across the entire water holdup range, meeting production requirements. Furthermore, in addition to measuring water holdup, the instrument also measures the gas volume fraction in the three phases, although the oil-water ratio was known in the test. The results show that the instrument can determine the gas volume percentage in a liquid exhibiting a foamy outflow pattern. 2. Compared to the past, exploration and development companies now face greater risks and more complex drilling environments, making accurate formation maps and reservoir mechanisms crucial. Current seismic measurement methods, such as towed floating cable geophone assemblies, temporary seabed-deployed seismic geophones, and downhole cable-deployed seismic geophones, can provide measurements of the target oil-producing area. However, these methods have relatively high operating costs, cannot be deployed into the well, or are limited by environmental conditions. Furthermore, the images provided are incomplete, discontinuous, and have relatively low resolution, making continuous real-time reservoir dynamic monitoring difficult. Fiber optic downhole seismic geophone systems can solve these problems, providing permanent high-resolution four-dimensional reservoir images throughout the entire well's lifespan, greatly facilitating reservoir management. These downhole seismic accelerometers receive seismic waves and process them into formation and fluid front images. Permanent downhole fiber optic three-component seismic measurements have high sensitivity and directionality, producing high-precision spatial images. They provide not only near-wellbore images but also images of the formation around the wellbore, with measurement ranges reaching thousands of feet in some cases. It operates throughout the entire lifespan of the oil well, withstanding harsh environmental conditions (temperatures up to 175℃, pressures up to 100MPa). It has no moving parts or downhole electronics, is encapsulated in a 2.5cm diameter protective shell, and can withstand strong shocks and vibrations. It can be installed in complex completion strings and confined spaces. Furthermore, the system features a large dynamic range and wide signal bandwidth, with a signal bandwidth of 3Hz to 800Hz, capable of recording equivalent responses from extremely low to extremely high frequencies. 3. Laser-Fiber Optic Nuclear Logging Technology: Laser and fiber optic technologies can be used to develop downhole sensors for logging in wells filled with non-transparent fluids such as crude oil and mud. Research on laser-fiber optic nuclear sensors is prevalent abroad, with numerous research papers published in the United States, Germany, Russia, and Belgium. Laser-fiber optic nuclear sensors are developed based on fiber optic communication and fiber optic sensors. They utilize physical effects such as photoinduced loss and photoluminescence, offering significant advantages over conventional nuclear detectors and representing a typical interdisciplinary field. Fiber optic nuclear logging technology is essentially nuclear detection technology under specific environments. Its typical advantages are: (1) Sensitive probes can be developed for different energy levels of nuclear detection. (2) Due to the application of photoluminescence, the probe can be located thousands of meters downhole, while the photomultiplier tube is connected by a transmission optical cable and placed above the well, far away from the harsh downhole environment (high temperature and high pressure), thus extending its service life. (3) Fiber optics have high-speed and high-capacity transmission capabilities and can also carry signals from other downhole instruments. However, laser fiber optic nuclear detectors also have disadvantages, mainly in terms of the protective coating that withstands high temperature and high pressure, the mechanical strength of the transmission optical cable, and the low attenuation loss of the radiation-resistant transmission optical cable. III. Conclusion and Outlook As can be seen from the analysis in this paper, fiber optic sensors, with their unique advantages, can be widely used in reservoir parameter monitoring (including temperature, pressure, and multiphase flow), acoustic detection, and laser fiber optic nuclear logging in oil and gas wells, greatly enriching the understanding of reservoirs by oil and gas companies and facilitating the optimization of oil and gas field development and maintenance. It is worth mentioning that this system can obtain the injection pressure and temperature of water in real time, thereby determining whether the pressure exceeds the standard and preventing casing damage caused by excessive pressure. This is a completely new field, and there are no reports or introductions on this aspect domestically or internationally. To date, major oil production and service companies worldwide have invested heavily in researching and developing the application of fiber optic sensors in reservoir evaluation, and many fiber optic sensor research institutions are also dedicated to this emerging field. It is conceivable that the next generation of fiber optic sensors, after overcoming its shortcomings and disadvantages, will be widely adopted, more effectively helping to understand the dynamic level of oil and gas extraction in real time. Major oilfield companies can fully utilize this beneficial information to achieve and maintain optimal oilfield production, thereby maximizing reservoir recovery. At the same time, due to the rapid development of the Internet, well condition parameters monitored by fiber optics can be transmitted in a timely manner, enabling oil industry-related production and service companies to more effectively analyze and evaluate assets worldwide.