8
Fiber Optic Sensors in the Oil and Gas Industry
Current and Future Applications
Abstract
The use of fiber optic sensors in the oil and gas industry has continued to grow over the past few decades. This chapter examines the various types of fiber optic sensor technologies that are used today and explains some of the applications that are benefiting from fiber optic sensing. Where applicable, descriptions of the different extraction techniques will be explained. The chapter concludes with a brief discussion of potential future directions.
Keywords
Fiber optic sensor; Gas industry; Oil industry; Pipeline monitoring; Steam-assisted gravity drainage; Thermal monitoring
8.1. Introduction
Fiber optic sensors have found applications in multiple industries, and their use has been gradually growing since the 1980s. Since the late 1990s, the use of fiber optic sensors in the oil and gas industry has greatly expanded, especially for in-well monitoring applications [1,2]. Throughout the late 1980s and 1990s the use of Raman-based distributed temperature sensing (DTS) was explored. The 2000s included the commercial introduction of Bragg grating-based pressure and temperature (P/T) gauges and multiplexed array temperature sensors [3,4]. During this time, fiber optic sensors have also been used to monitor pipelines transporting hydrocarbon materials over great distances. Flowmeters and seismic sensing systems based on interferometric sensing principles were also introduced in the 2000s. Further commercialization of DTS and Brillouin systems for thermal monitoring applications expanded in the 2000s. The 2010s have seen the emergence of distributed acoustic sensing (DAS) based on coherent Rayleigh scattering principles. Although these sensor techniques have the capability to provide fascinating data about the wellbore environment, it is the use of the data for various applications that provides value to the end users.
The use of fiber optic sensors for oil and gas applications has been driven in part by the inherent advantages that the technology offers. Often the applications make use of the fact that fiber optic sensors are a good sensor solution for harsh environment applications, including at temperatures exceeding 250°C such as in thermal well applications. Many other advantages of fiber optic sensors are also leveraged for these applications, including the ability to monitor physical parameters over long distances, the lack of electrical current needed at the sensing locations, the ability to multiplex many sensors on a single fiber, and the ability to sense multiple parameters on a single optical fiber. Multiplexing and multiparameter sensing may be accomplished through either wavelength division multiplexing (WDM) for Bragg grating-based systems or time division multiplexing for interferometric systems. Distributed fiber sensing systems also provide the advantage that the entire optical fiber acts as a sensor and receives measurements along the entire length.
An in-depth discussion of each current and potential application for fiber optic sensing in the oil and gas industry is beyond the scope of this chapter. Also, considering that just about every fiber optic sensing technique (Bragg gratings, Raman scattering, Brillouin scattering, Rayleigh scattering, and interferometric sensing) is currently used in the oil and gas industry, an in-depth discussion on each of the fiber sensing techniques and their particular detection techniques would also be exhaustive. The goal of this chapter is to provide a general overview of the more common applications in the oil and gas industry while not going into too much depth on the petroleum engineering aspects. The reader will find the required information regarding each sensing technique discussed in previous chapters of this book.
The first section of this chapter will provide a general overview of the oil and gas industry and introduce the areas where optical fiber sensing is currently used. The chapter will then discuss different applications in terms of pressure monitoring, temperature sensing, flow measurements, and acoustics. In general, a dominant form of fiber optic sensing is used for each of these general application areas. Where more than one fiber optic sensing technique is used, a brief comparison between the different techniques will be covered. The chapter will conclude with a discussion on potential future trends of fiber optic sensing taking into account the current market downturn experienced since the oil price collapse following the market peak of 2014.
8.2. Breakdown of the Oil and Gas Industry
The oil and gas industry can be broken down into three main categories referred to as upstream, midstream, and downstream. The oil production process begins in the upstream sector of the industry. The bulk of this sector is focused on applications in subterranean reservoirs. This sector of the industry is concerned with the exploration and production of hydrocarbon resources from the earth. Activities in this sector include seismic acquisition, drilling activities, well completion activities, hydrocarbon production processes, and artificial lift. Once the hydrocarbon material reaches the surface, it then transfers to the midstream sector for transportation from the well site to refineries that process the raw hydrocarbon to useful products. Transportation of the hydrocarbon is performed in many ways including truck, rail, ship, and pipeline. Once the hydrocarbon reaches the refinery it is then considered to be in the downstream sector. The refining process takes the raw hydrocarbon material and processes it into useful products such as gasoline, heating oil, asphalt, and plastics, to name just a few [5]. The downstream sector also includes the transportation of the processed material to retail distribution centers, which again can be performed by truck, rail, ship, and pipeline.
Fiber optic sensing has found use in each of the different sectors, but by far the main focus has been on monitoring in the harsh environment of the subsurface oil well in the upstream sector. Therefore, this chapter will mainly focus on upstream sector monitoring activities. In the midstream sector, the main application for fiber optic sensing is in pipeline monitoring [6]. Some applications that monitor civil structures such as rail-line monitoring could be considered here as well, since rail is another method of transportation of the hydrocarbon products, but these applications will be left for chapters on infrastructure monitoring. In the downstream sector, the use of fiber optic sensors has been somewhat limited to date. There are a number of companies marketing fiber optic sensors for pressure, temperature, and chemical monitoring within the refining process. These applications typically fall under the heading of industrial process monitoring applications.
An interesting aspect of the upstream oil and gas industry that is relevant to the discussion in this chapter is that there are different types of wells. At the beginning of an oil field development project, wildcat and appraisal wells are drilled. These are typically low cost and do not involve fiber optic sensing systems. These wells are used to locate and evaluate the subsurface reservoir by examining core samples, pressure measurements, and temperature data. Once the reservoir is ready to be produced, production wells are drilled. Production wells allow hydrocarbon products to flow to the surface. At first, the natural pressure of the subterranean reservoir may be enough to push the fluids to the surface. However, as the reservoir is produced the natural pressure drops and other techniques are required to get the fluids to the surface. One method is to use injection wells. Injection wells are used to inject other fluids (typically water or gas) into the reservoir to increase the reservoir pressure. Another type of well is an observation well. As its name implies, this well type is used for measuring various reservoir parameters at different locations. Pressure, temperature, and seismic measurements are typically performed in observation wells.
Another interesting aspect of the upstream sector is the field of artificial lift or enhanced oil recovery (EOR). Production wells (called producers) are often fitted with some form of artificial lift such as a reciprocating rod lift (the nodding donkey most commonly associated with an oil well) or an in-well pump such as a progressive cavity pump (PCP) or electrical submersible pump (ESP). Producers can also be implemented with gas lift techniques. In these applications, gas, which is lighter than the production fluid, is injected into the producer well to lower the density of the produced hydrocarbon, making lift from the reservoir more efficient. Efficiency is measured in terms of how much energy is required to produce one barrel of oil. Along the same lines as artificial lift systems are the EOR techniques. EOR techniques involve doing something to the reservoir to make the hydrocarbon easier to be brought to the surface. One example of an EOR technique is the injection of steam into the wellbore to decrease the viscosity of heavy oil (bitumen). Once the viscosity is decreased, the heated hydrocarbon can then be pumped to the surface. The steam injection process is popular in the Canadian oil sands and falls under either steam-assisted gravity drainage (SAGD) or cyclic steam stimulation (CSS). SAGD wells typically consist of a well pair, in which a horizontal injection well is positioned about 5 m above a horizontal producing well. During initial reservoir conditioning, steam is injected into both the injection and the producer well. Once a sufficient steam chamber is formed, the producer well is then placed into production mode. The heated bitumen falls owing to gravity to the producer well while the injector well continues to heat the reservoir to replace the thermal energy being lost through the production process. CSS wells are typically a single vertical well that is heated with steam for an amount of time, and then switched to production. As the name suggests, the well is cycled back and forth from injection to production for the life of the well. Observation wells are used for monitoring the reservoir in these applications as well. Another well type that may be used in these fields is an infill well. An infill well is essentially a production well that is placed in an area of the reservoir to drain an area that may be missed by the original producing wells. The infill well will also take advantage of the existing thermal chamber of the neighboring SAGD or CSS wells.
Hydraulic fracturing is another example of an EOR technique. In these reservoirs, the hydrocarbon is trapped very deep in the earth's surface and is held in tight formations. Once the production well is drilled, there is almost no fluid production because of the depth of the well and the hydrocarbon being trapped. To release the hydrocarbon and allow it to be produced at the surface, the tight formation must be fractured—typically by injection of fracturing fluid (mixture of sand or proppant, water, and injection chemicals). The pressure of the injected fluid causes the tight formation to form cracks and allow the sand or proppant to enter the formation. The permeability around the proppant material allows for the hydrocarbons to flow into the wellbore where it can then be produced at the surface. These wells typically have a very long horizontal length. To obtain a more effective fracture, the horizontal is divided into zones. The division into zones also helps with production, because the horizontal wellbore may pass through regions that are not within the reservoir, so blocking production from those zones is important for production efficiency.
A final well type that has used fiber optic sensors is CO2 sequestration wells. There has been an increase in interest in storing captured CO2 emissions in subterranean wells. The sequestration process involves drilling a well below the caprock layer and injecting the CO2 into a reservoir (this can be used as an injection well for a hydrocarbon reservoir). Once the injection is completed, the well is sealed and the CO2 is considered captured. Depending on the well location, regulatory mandates may require monitoring to ensure the CO2 is staying in the well. This can involve the use of fiber optics to monitor pressure and temperature and listen for seismic events indicating leaking CO2.
8.3. Thermal Monitoring
The first use of fiber optic sensors for in-well monitoring applications was the use of distributed temperature sensors based on Raman scattering. Trials of the technology began in the late 1980s [7]. Today, thermal monitoring has become one of the major applications for fiber optic sensing in the oil and gas industry. The main technology used for these applications is Raman scattering–based DTS, but Brillouin scattering has also been used in the industry for distributed sensing. Bragg grating–based temperature monitoring is also used to measure temperature at a multitude of points along the wellbore. The Bragg grating sensor technique is referred to as array temperature sensing and has been used in the industry, particularly in the extreme environment of SAGD wells [8]. This chapter will review applications of thermal monitoring and the fiber optic sensing techniques used.
8.3.1. Pipeline Monitoring
Pipelines are used to transport hydrocarbon materials great distances. This midstream sector application is advantageous for fiber optic sensing systems for a number of reasons, including sensing over long distances. Furthermore, because optical fiber is used for long-distance communications, optical fiber cables are sometimes laid along with pipelines, because this represents a straightforward right of way and the optical fiber cable can be buried with the pipeline with minimal additional cost. Therefore, many pipeline structures will have existing available optical fiber for monitoring (referred to as dark fiber because it is not being used for communications). This section will cover pipeline monitoring applications including leak detection, ground movement detection, and intrusion detection.
8.3.1.1. Leak Detection
A main application for pipeline monitoring using fiber optic sensing is leak detection. As described previously, the common fiber path is running along with the pipeline often below the pipeline. If a leak occurs, material will most likely travel down to the location of the fiber path. If there is a temperature variation between the pipeline fluids and the ambient environment, then the Raman-DTS or Brillouin systems will measure a temperature change at this location [9]. Factors affecting the performance of these systems include the spatial resolution of the monitoring system compared to the size of the leak. It may take some time for a small leak to register on the system if the temperature change is small, owing to spatial averaging of the distributed measurement.
Another methodology for leak detection involves using DAS techniques to listen for leaks in pipeline structures. For these cases, the leak must generate sufficient noise to be detected by the DAS measurement. There is typically not enough acoustic energy in a slow liquid leak, where the thermal technique is more appropriate. Frequency banding techniques can also be used to improve the signal-to-noise quality and “focus” the measurement on the leak detection application [10].
Another potential application for thermal monitoring of pipeline structures is identifying locations where insulation may be damaged, leading to a loss of thermal containment (for heated fluid or cold fluid transport) [11]. Similar to leak detection, these applications monitor for changes in the thermal profile along the pipeline. If the degradation of the insulation is a slow process, then setting appropriate thresholds for damage detection may be difficult.
8.3.1.2. Brillouin Monitoring of Temperature and Strain
Pipeline structures are susceptible to damage due to ground movement, including earthquakes, landslides, and erosion. Fiber optic monitoring of the strain or deformation of the pipeline through Brillouin scattering techniques has been used to monitor the movement of the pipeline [9]. These applications typically require the optical fiber to be attached to the pipeline structure and not just located near the pipeline as with leak detection.
8.3.2. Downhole Thermal Monitoring Applications
Measurement of the wellbore temperature is used for many applications. Downhole thermal monitoring applications typically make use of the natural geothermal gradient that exists in the subsurface. The geothermal gradient is essentially a constant increase in temperature with depth that can be influenced by geological formations and fluid movements. To determine the geothermal gradient, a well must be nonproducing or shut in (no fluid movement) for a length of time to allow for a stable equilibrium of the thermal profile along the wellbore [12].
Thermal monitoring is used to detect changes in the thermal gradient as indications of hydrocarbon material moving in the wellbore. Also, EOR applications such as SAGD make use of thermal monitoring to track the injection of steam and the steam chamber growth. These and other topics are discussed further in the sections below.
8.3.2.1. Liquid Flow
As liquids flow in the wellbore, they cause a deviation from the geothermal gradient [13]. For example, a fluid will enter the wellbore at a temperature corresponding to the local geothermal temperature; as the fluid rises in the wellbore to be produced it will warm the wellbore above while the fluid loses some of its heat. If there is another entry point encountered, the fluids will mix, causing a decrease in temperature of the original rising fluid. As shown in Fig. 8.1, there is no production at the bottom of the well, so the temperature matches the geothermal gradient until the point of first entry. Above the point of first entry, the temperature of the wellbore increases above the geothermal gradient. At the second point of entry, the fluids mix, resulting in a temperature decrease. Above this point, the wellbore temperature stays above the geothermal gradient.
8.3.2.2. Gas Entry
Monitoring for gas entry is very similar to the liquid flow monitoring discussed previously. The main difference is that as the gas enters the wellbore, adiabatic expansion leads to a cooling effect. As might be realized, a well that is producing both liquid and gas phases will be much more complicated to analyze.
8.3.2.3. Injection Monitoring
As described in Section 8.2, one type of well used in the oil and gas industry is a water injection well. As cold water is injected into the formation, the region around the wellbore will cool away from the geothermal temperature. Once the well is shut in and there is no flowing liquid, the well will begin to warm back to the geothermal gradient. Warm-back analysis is a measurement technique that is routinely performed on water injection wells to determine regions where the water has been taken into the reservoir. Regions where more water has been taken into the formation will take longer to warm back [14].
8.3.2.4. Wax Buildup
Sometimes, the temperature and conditions in a producer well allow paraffin to solidify and form wax buildup within the tubing producing the hydrocarbon. This leads to a blockage of the producer well and lost production [15]. DTS data have been used to track the exact locations (depths) of wax accumulation by analyzing trends in the temperature data over time. There is even one known instance of tracking the movement of a wax plug within the wellbore to a region of higher temperature, which melted the wax plug and returned the production well to normal operation. This capability saved the operator the cost of performing a well intervention to remove the wax plug [16].
8.3.2.5. Gas Lift Optimization
Artificial lift techniques are used to assist with the production of reservoir fluids from the subsurface, sometimes by decreasing the density of the fluid column in the vertical section of the well above the reservoir. One method of artificial lift is to inject gas (low density compared to liquids) to reduce the weight of the produced fluid. To optimize gas-lift production, the entry point for the lift gas must be precisely controlled and monitored [17,18]. The Joule–Thomson effect on gas flowing through a gas-lift mandrel causes the producing fluid to cool. Therefore, acquisition of a thermal profile provides a means for detecting through which mandrel(s) gas is passing, as illustrated in Fig. 8.2. In addition, a mandrel that is slugging gas, rather than operating normally, would be readily identified using time-lapse thermal monitoring. Suboptimal efficiency can thus also be rectified. A permanently installed fiber optic cable with completion down to the lowermost gas-lift mandrel can readily obtain the thermal profile.
8.3.3. Steam-Assisted Gravity Drainage Optimization
One of the main applications of fiber optic thermal monitoring has been in the field of SAGD wells. These and other thermal well types increase the mobility of the hydrocarbon material (bitumen) through the injection of high-temperature steam. Steam injection temperatures are typically well over 200°C. At these elevated temperatures and extreme environmental conditions, DTS measurement techniques based on Raman scattering have been plagued by issues of hydrogen darkening [19]. Improvements in optical fiber materials, including pure-core optical fibers, have been made to this technology, but reliability is still an issue [3]. The use of wavelength-multiplexed fiber Bragg grating (FBG) sensors has proven resilient in these applications and they have been used in these applications since 2007.
For SAGD applications, two horizontal wells are drilled that are separated by approximately 5 m vertically (as pictured in Fig. 8.3). To begin the process, both wells are used as injection wells and steam is injected to warm the reservoir. After a certain period of time, the bottom well is turned into a production well, and the viscous bitumen drains to this well and is pumped to the surface. During the time of dual injection (also known as circulation or startup), the use of real-time temperature measurements from FBG sensor arrays is used to monitor the steam flood to the well [20]. An example of thermal data from a steam restart is shown in Fig. 8.4. The sensor responses provide a measure of how fast the steam front is moving along the horizontal well and of the maximum steam temperature (approximately 238°C for this particular application). In the figure, the thermal response of the first four FBG sensors is shown. As the steam progresses along the wellbore, each sensor responds based on the velocity of the steam front and the physical location of the sensor. After the first two sensors reach maximum temperature, the steaming is stopped and the sensors measure the cooling rate. The sensor closest to the wellhead is the last to cool down. Thermal response data, such as those shown in the figure, can be used by reservoir engineers to model the reservoir and plan for future production operations.
Thermal monitoring is also used to measure the temperature difference between the injection and the production well. If the temperature in the production well increases to meet the injection well temperature, this is an indication of steam breakthrough to the production well. If this occurs, the production well will return the steam (or condensed water) to the surface instead of the petroleum product. Keeping an optimum temperature difference between the injection and the production well is key to optimizing SAGD wells and is referred to as subcool monitoring [20].
8.4. Pressure Monitoring in the Downhole Environment
Another key parameter to measure in the downhole environment is pressure. Downhole fiber optic pressure gauges are typically constructed from either Bragg grating sensors or Fabry–Perot sensors. Bragg grating–based sensors have the advantage of being more easily multiplexed on a single optical fiber and have been the primary method for in-well pressure sensing. Bragg grating sensors also require some form of temperature compensation and this leads to the measurement of temperature at the gauge location, as well. In general, two or more Bragg gratings are incorporated in the sensing mechanism to provide the temperature compensation. The first fiber optic pressure gauges installed were based on resonant microelectromechanical system structures where the optical fiber delivered light to the sensing mechanism that had varied the response based on applied pressure [3,4]. These designs were soon replaced with Bragg grating–based devices that provided more stable and reliable operation. The Bragg grating devices also take advantage of higher return optical signals compared to interferometric and distributed sensing systems, allowing them to overcome hydrogen attenuation effects. Fabry–Perot-based sensors are typically a diaphragm design and the response of the sensor is highly dependent on the mechanical properties of the diaphragm.
Downhole fiber optic pressure gauges must have a very rugged design, yet be able to provide sensitive response to the applied pressure. Figs. 8.5 and 8.6 show examples of commercially available fiber optic P/T gauges. The design includes Inconel materials for corrosive resistance, appropriate wall thickness to support pressure loading, and internal design measures to handle CTE (coefficient of thermal expansion) mismatch between the glass optical components and the metal elements. CTE mismatch is a major design issue for the P/T gauges in that the metal materials will expand much more than the glass components when exposed to high temperatures expected in downhole applications.
8.4.1. Drawdown
When wells are first brought onto production and fluids are pulled from the reservoir, the reservoir pressure will decrease or draw down. This creates a differential pressure that drives fluids from the reservoir into the wellbore. Hence, production rates are related to the drawdown. If the production rate is too high, the well may begin to produce sand, leading to untimely wear of in-well components. The production can be choked off to slow production, leading to an increase in the wellbore pressure, thus decreasing the pressure differential between the reservoir and the wellbore.
8.4.2. Pressure Transient Analysis
A key pressure monitoring application is pressure transient analysis. This analysis makes use of dynamic measurements of pressure in the wellbore during a shut-in process. By measuring the pressure response during the shut-in process, information on characteristics of the reservoir formation and the ability to produce fluids from the formation are provided. During the life of the well, various activities may lead to requiring the well to be shut in or stop production. A permanently installed P/T gauge can provide pressure buildup data during this time [21]. This could potentially eliminate a planned intervention by providing the required pressure data at a time of opportunity. This is similar to condition-based maintenance compared to schedule-based maintenance.
8.4.3. Lift Monitoring
During the life of most wells, some form of artificial lift will be required. Artificial lift provides a means to reduce the density of the fluid in the well to allow for easier production. This can be accomplished by injecting gas into the wellbore to reduce the density of liquids (gas-lift applications) or using a pump to pull the liquids out of the vertical well (ESP, PCP, etc.). In any pumping process, having an accurate, real-time measurement of pressure is a key component to optimization. Measuring the pressure outside of the pump tubing can ensure that the pump is below the fluid level and prevent instances of cavitation, which can damage the pump. P/T gauges are also used to measure intake and discharge pressures for the in-well pumps [22]. This information helps to determine the health of the pump system.
8.4.4. Pressure and Temperature Above the Packer
Another application for the fiber optic P/T gauges is monitoring the pressure in the wellbore annulus to ensure production packer integrity and performance. The production packer provides a barrier to flow in the wellbore that forces all well fluids into the production tubing and isolates production zones from one another. Therefore, monitoring pressure around the production packer is a key technique to ensure packer and well integrity [1].
8.4.5. Zonal Monitoring
For some reservoirs, segmenting the wellbore into different zones is advantageous. In this manner, areas of the wellbore that are nonproducing or that would produce only water or sand can be avoided. For these multizone wells, packers are used to partition each zone as illustrated in Fig. 8.7. The P/T gauges shown in the figure are positioned to measure pressure in the near wellbore region and pressure within the tubing. The dual-gauge mandrel on which the P/T gauges are mounted has a pressure port to the inside of the tubing, and the P/T gauge is mounted with seals to prevent leakage. Using a dual-gauge mandrel allows for measurement of both annular and tubing pressure at the same location along the wellbore, which is important to ensure that there is no pressure communication between annulus and tubing regions. The illustrated mandrel design also allows for the downhole optical fiber cable to continue farther into the well formation to connect to other P/T gauges in deeper zones.
8.4.6. Lift Monitoring and Steam-Assisted Gravity Drainage Applications
As discussed previously, the SAGD process calls for the injection of ultrahigh temperature steam under pressure to be injected into the wellbore. Downhole pressure measurements are used to ensure that steam quality matches the assumed injection steam quality. Another application for SAGD production wells is measuring the pressure at the toe and at the heel of well. This differential pressure between the toe and the heel of the horizontal section provides an indication of the driving force to move the fluid to the pump at the heel of the well [23].
8.4.7. Interference Testing
Reservoirs typically have multiple wells pulling production fluid from the subsurface. To optimize production from the reservoir across the different wellbores, a measure of interference (or communication) between the wells is required. Interference testing allows for a determination of the level of influence a neighboring wellbore has with another well in the field. A typical interference test procedure would call for one well to be shut in and allowed to reach a stable pressure. Then a neighboring wellbore would be injected with a fluid (water) and the pressure within the shut-in wellbore would be monitored to determine how long it takes the injection well to influence the pressure of the shut-in well [24].
8.5. Flow Monitoring
An important aspect of production monitoring is monitoring the fluid flow within the wellbore and determining what the makeup of the fluid is. The use of an in-well flowmeter can reduce or eliminate the need for surface flow testing. This results in improved operation, increased safety, and a reduction in potential environmental effects. Two fiber optic sensing techniques that have been used for flow monitoring are interferometric and DAS. Interferometric sensing techniques make use of low-reflectivity, matched FBGs to create a series of Fabry–Perot cavities. The optical fiber making up each cavity is wrapped around the production tubing (creating a flow mandrel) [25]. The Fabry–Perot cavities detect eddy currents of the turbulent flow in the production tubing and use the measured signals to determine flow rates. DAS technology has been shown to provide the ability to determine the location of gas flow into the well. Using surface total flow measurements, a statistical analysis of the percentage of total flow can be assigned to the different regions of the well.
8.5.1. Interferometric Flowmeter
The flowmeter mandrel is illustrated in Fig. 8.8. The flowmeter is often installed with a fiber optic P/T gauge that is interrogated along the same optical fiber by means of WDM techniques. A fiber optic connector is used to connect to the downhole optical cable for transmission of optical signals to the instrumentation on the surface. The optical flowmeter is full bore, meaning that there are no obstructions or reductions in flow area (such as a venturi) to interfere with the flowing fluid. This allows the flowmeter to have bidirectional functionality to monitor either injection processes or fluid being produced and removed from the reservoir—with no required change to the completion components of the well.
Figure 8.8 Illustration of an in-well fiber optic flowmeter with flowmeter mandrel, including locations for a fiber optic connector for connection to downhole cable, pressure and temperature (P/T) gauge location, clamps for P/T gauge protection, and control line cable bypass.
The design of the in-well fiber optic flowmeter uses interferometric sensing principles to measure pressure fluctuations caused by turbulent fluid flow within the tubing. The flowmeter measures two fundamental parameters that directly relate to the flow properties of the fluid: (1) the flow velocity or flow rate of the fluid and (2) the speed of sound (acoustic velocity), i.e., the speed at which a pressure wave propagates through the fluid [25]. The speed of sound is dependent on the ratio of oil, water, and gas flowing within the tubing. A key component of in-well flow monitoring is the ability to measure these multiphase flows, in other words, to determine the relative amounts of oil, water, and/or gas flowing in the well. For two-phase flow (oil and water), the speed of sound can provide a determination of the ratio of water and oil flowing in the well. For three-phase flows (oil, water, and gas), a measure of the density of the fluid is also required and can be obtained by measuring the pressure differential in a vertical section of the well [26].
8.5.2. Injection Monitoring
As explained earlier, reservoirs may require injection of water or gas to maintain reservoir pressure. To optimize placement of the injected fluid, a multilateral well may be used with diverters controlling how much fluid goes to the different laterals. A multilateral well is a well that branches off downhole to reach different areas of the reservoir (as illustrated in Fig. 8.9). The ability to have multilateral wells decreases the cost for completion because only one wellhead and drill point is needed. As pictured in Fig. 8.9, the wellbore is split into different sections downhole, allowing for access to different parts of the reservoir through one access point. The in-well flowmeter can be used to monitor and control the injection process in these wells [27]. A further advantage of the fullbore flowmeter is that it is bidirectional. This allows the injection well to be converted to a production well and maintain full functionality.
8.5.3. Production Monitoring
As alluded to earlier in this chapter, the main goal of any well is the production of hydrocarbon fluids. A downhole flowmeter allows for an in-depth understanding of what is being produced within the wellbore. Use of a downhole flowmeter provides a measurement of production from different zones of a well [28]. This can be achieved either with a flowmeter placed above each producing zone or by installing meters between each zone and using total flow measured at the surface to obtain the contribution of the uppermost zone. If the well has multiple lateral sections, a flowmeter can be placed at the top of each lateral to determine the production for the different laterals. Use of a downhole flowmeter may also reduce the need to perform surface flow measurements to determine the productivity of individual wells, which will reduce the need for some surface equipment such as separators, leading to reduced facility requirements.
Another advantage to measuring the flow data in the downhole environment is that the higher pressures and lower gas volume fractions downhole typically result in conditions that are more conducive to multiphase flow measurement than those at the surface. Hydrocarbon production can lead to a wide variety of flow regimes such as slug flow or bubbly flow, which can have an impact on flow measurements [28].
In tight gas wells, DAS technology is being used to determine the amount of gas being produced in the wellbore along the horizontal in the different stages. By analyzing the relative acoustic energy at each stage, a qualitative measurement of the well production can be deduced. This enables the DAS data to be reduced to a red, yellow, and green light image to allow production engineers to determine the locations of the reservoir that are more productive. Combining these data with cumulative flow or production information can generate quantitative production data for reservoir analysis [29].
8.6. Seismic Monitoring
Seismic monitoring allows scientist (geologists) to get an understanding of the geology of the subsurface by measuring the reflections of acoustic sources from subsurface formations. There are two main techniques involved with seismic surveys. The first of these is active seismic, where an impact or explosive charge is used to create a sound wave that travels through the subsurface and is received by in-well sensors, or the reflections from the sound wave are received by surface sensors. The other type of seismic process is called microseismic, where the seismic sensors listen for natural sources coming directly from the subsurface. These sources could be from movement of fluid in and around the wellbore and the movement of fracking fluid into the reservoir. Two types of fiber optic sensors have been used for seismic monitoring. The first was sensors based on interferometric principles that utilized the motion of a mass to strain the optical fiber [30,31]. More recently, DAS systems have been increasing in use in seismic monitoring applications.
8.6.1. Vertical Seismic Profile
A vertical seismic profile (VSP) survey requires the seismic sensors to be placed within the wellbore. The VSP provides a high-resolution image that begins at the wellbore and extends into the reservoir toward the active source on the surface [12]. With the sensors located in the wellbore, the images obtained are typically of higher resolution than the surface surveys. Traditional electronic VSP applications are run on wireline (or temporary applications). For these applications, the well must be shut in and nonproducing during the VSP acquisition. With the fiber optic techniques, the sensors can be installed in a permanent fashion and the surveys may be run while the well is under production [32]. Fiber optic techniques based on interferometric sensors are limited in the number of sensing locations available, whereas in the DAS system the entire optical fiber can be used for acquisition purposes with a spatial resolution of 10 m typically.
8.6.2. Microseismic Monitoring
Microseismic techniques essentially listen for naturally occurring effects. One application that fiber optic sensors have been used for is monitoring carbon sequestration wells [33]. In these applications, regulatory requirements are in place to ensure the sequestered carbon is being securely held in the subsurface formation. The microseismic monitoring is continuously listening for potential cracks in the caprock layer and leakage of the carbon gas through the wellbore.
Another microseismic application is monitoring the fractures that occur during and after a hydraulic fracture stimulation process. By acquiring these data, reservoir and production engineers can gain an understanding of the nature of the level of fracture induced in the different zones. This enables the determination of where produced fluids are coming from within the reservoir and assist in the determination of reservoir depletion/drainage.
8.6.3. Seismic Surface Arrays
The major application in which optical-fiber sensing has been used in seismic surveys is seismic surface arrays. Seismic surface arrays consist of a system of fiber optic seismic sensors spread over a wide area. Fiber optic sensors with the ability to reach long distances and be highly multiplexed have found applications in subsea monitoring where electric sensors have had trouble operating in such conditions [34,35].
8.7. Acoustic Monitoring
The development of DAS technology has expanded the number of applications involving fiber optic acoustic monitoring for the oil and gas industry. These applications include both pipeline and downhole monitoring applications. Prior to the onset of DAS technology, paired FBG interferometric sensors were used for acoustic sensing. These systems were based on interferometric sensing techniques similar to the flow sensors discussed in the previous section. One application, pipeline leak detection with DAS systems, was discussed previously in Section 8.3.1.1. This section will provide information on some of the newer applications being enabled by DAS acquisition systems.
8.7.1. Pipeline Intrusion Detection
In addition to leak detection, another issue with pipelines is the concern of theft of the hydrocarbon material the pipeline is carrying or sabotage of the pipeline. DAS has been a breakthrough technology for pipeline intrusion detection. It is difficult to guard multiple kilometers of pipeline through traditional methods, including video surveillance and manned monitoring. The ability of DAS measurements to detect various dynamic events over long distances plays into the advantages of using fiber optic sensing. Signal processing of the DAS data has been able to detect and discriminate activities near the pipeline such as a person walking, vehicle traffic, use of heavy equipment, and a person digging [36]. The effectiveness of the DAS systems is somewhat determined by the soil consistency. DAS detects the dynamic strain signal or pressure waves traveling through the soil to the optical fiber cable. The sensitivity of the DAS response is dependent on how well the pressure wave travels through the soil and interacts with the cable structure. For example, the pressure wave will travel differently through sand compared to mud. Therefore, the DAS system response should be calibrated along the pipeline structure to adjust system parameters for the various soil structures encountered.
8.7.2. Hydraulic Fracture Monitoring
One of the main applications for downhole DAS monitoring is the field of hydraulic fracture monitoring. Applications around microseismic monitoring have been discussed in Section 8.6.2. However, the use of DAS monitoring has enabled the ability to monitor the acoustic energy generated during the fracture process. As the fracture fluid flows through the perforated orifices and into the formation, the optical fiber can detect the acoustic energy generated during this process [37]. Pumping engineers have used this information to determine if a region is not taking any fluid (no or little acoustic energy detected). Analyzing the response over multiple stages can provide a qualitative measure of the effectiveness of the fracture process.
8.7.3. Slugging
Detection of the sound of the flowing fluid provides indications of other well conditions. At times, the flow of the fluid in the wellbore can become erratic or periodic. The well fluid can produce slugs that move slower in the wellbore and can restrict flow especially in the vertical section of the well. Analysis of the acoustic energy can indicate conditions of slugging and allow the well operators to take corrective actions [29].
8.8. Future Directions
Although fiber optic sensing technology is far from being routinely deployed, the technology is recognized as providing value in numerous applications as discussed in this chapter. The advantages of fiber optic sensing continue to be leveraged to provide robust long-term measurements in the oil and gas industry. These advantages include all-optical designs requiring no in-well electronics, which enables operation in high temperatures, and the ability to multiplex many sensors on a single optical fiber—where the ability to monitor multiple sensors on a single optical fiber is important for multizone applications. Fiber optic sensing also allows for multiparameter sensing along a single optical fiber: Bragg grating–based P/T gauges and temperature array sensors can be placed on the same optical fiber as flowmeters, DAS monitoring, etc. Multiparameter sensing combined with multifiber cables provides a means to interrogate the wellbore and provide data throughout the life of a well on a single sensing cable. Future applications include extending the complexity of the sensing systems to multiple parameter sensing from a single downhole cable as illustrated in Fig. 8.10. A major consideration of oil and gas applications is safety. Through multiparameter sensing, the number of penetrations into high-pressure areas can be limited. With the ability to perform multiple measurements on a single optical fiber and the ability to have multiple optical fibers in one cable, the use of fiber optic sensing for in-well monitoring applications can be considered a key safety feature.
It is difficult to predict the next sensing technology that will find a useful application in the oil and gas industry. There are possibilities within the downstream market for industrial process monitoring and environmental monitoring. Another potential application for fiber optic sensing in the oil and gas industry is chemical sensing. There are many different types of fiber optic chemical sensors being researched and marketed today for various applications, including chemical threat detection, medical research, and food quality and safety testing [38]. Adapting these technologies to the various oil and gas markets will be a challenge, but the ability to detect and monitor process gases in the downstream sector, monitor corrosion or leakage species from pipelines, or monitor chemical species in the wellbore can provide efficiency and cost savings.
The growth in the use of fiber optic sensing for oil and gas applications to date has been driven by market demands. From one point of view, the sheer number of applications that fiber optic sensing has reached could be considered very impressive. However, in many cases there are existing “traditional” technologies that, although they may not be as well suited to the application or provide the level of data that fiber optic sensing does, they are known technologies and often cheaper to implement. The oil and gas industry (like many industries) is filled with booms and busts. At the time of this writing, the oil and gas market is in the midst of a bust. After falling below $30 a barrel the price of oil has struggled to find stability, and the industry is now facing a “new normal” of lower capital and R&D spending. This sort of market downturn places an incredible strain on the development and adoption of technology. Although fiber optic sensing technology has proven to be a viable solution in many applications, the uptake in its use has been limited by a perceived issue of reliability and a real issue of increased up-front cost. Both of these will be overcome in the future as the advantages of the lifetime benefits of continuous monitoring with fiber optic sensors are realized and the fact that the up-front cost is offset by these lifetime benefits is recognized. As the adoption of fiber optic sensing becomes more routine, improvements in manufacturing and volume pricing will lead to reduced up-front costs.
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