Distributed Temperature Sensing (DTS) is an emerging technology which allows temperature measurement and transmittal along the entire length of the well. An enclosed fiber-optic cable is deployed into the well to allow a continuous, real-time snapshot of the well's temperature profile. Since its introduction in 1995, DTS has had an increasing number of applications including determining production and injection profiles, monitoring stimulation operations, and performing gaslift surveys. This paper discusses DTS as a method for downhole leak detection based on a North Slope field trial conducted between 2004–2006. Twelve operations were performed using two different vendors' retrievable DTS systems, successfully identifying tubing, production casing, sand plug, and packer leaks. Theory, case histories, and future improvements are summarized in this paper. Additionally, a comparison between conventional leak detection logs is presented along with the advantages and disadvantages of DTS surveys. Introduction Prudhoe Bay, Alaska, located on the North Slope is a mature enhanced oil recovery/waterflood oil field which has experienced well integrity issues as the field ages. Conventional leak detection logs (LDL's) are commonly performed as an operational diagnostic tool when annular communication is detected. In 2004, a field trial using temporary, slickline- and wireline-conveyed DTS was initiated to determine if the system could be used as a reliable leak detection method. Conventional leak detection diagnostics. Conventional LDL's are typically performed on wireline at Prudhoe Bay. The toolstring includes temperature, pressure, and casing collar locator (CCL) sondes. If the leak is in the tubing and is large enough, a spinner and density sonde may be included as well. With the well shut in, a thermal baseline pass is logged from surface to below the packer, typically at 150 feet per minute (fpm). A second logging pass is then completed while pumping into either the tubing or the "A" annulus (Figure 1), depending on the size and location of the leak. Repeat passes of logged anomalies are performed to ensure accurate leak identification, often at slower logging speeds.

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A new ultrasonic leak detection logging tool conveyed on electric line, and recently on wireline in memory mode, has been introduced which can detect leaks as small as 1/2 cup per minute. This revolutionary tool has been used to accurately identify leaks in tubing and behind pipe. Wells that otherwise would immediately be slated for a rig workover (RWO) have been repaired with non-rig solutions. Ultrasound energy has very rapid attenuation and the ability to transmit through various media and behind pipe. These attributes allow pinpoint accuracy for leaks as small as 0.0024 gallons per minute (gpm). The tool incorporates data acquisition equipment and filtering algorithms which allow continuous logging. The technology is far superior to old-style noise logs which require time consuming stationary counts. To date, BP has run 21 ultrasonic leak detection logs in Alaska fields with an 81% success rate. The recent ability of this tool to be conveyed in memory mode has opened up additional logging opportunities. This has led to the development of a new technique using nitrogen to identify wells that leak only to gas. Application of this tool has great significance for any operator concerned with well integrity, and particularly, in areas where rig workovers are expensive including remote, offshore, and arctic locations. Introduction BP operates several enhanced oil recovery and waterflood oil field which have experienced well integrity issues as the field matures. Non-rig tubing repairs have become a viable alternative to RWO's, which can easily exceed 1 million dollars. Repair methods include tubing straddles and coiled tubing packer repairs. The advantage over a conventional RWO is that there is no need to pull tubing, resulting in the well being returned to service faster. However, the main limitation for non-rig candidate selection has been in identifying leaks which are below the resolution of conventional leak detection methods. Often a well with annular communication had to be worked over because the leak point could not be determined. The ultrasonic leak detection tool has provided a step change in leak identification. Prior to its introduction, it was virtually impossible to detect leaks smaller than 1 gpm. Often the velocity and temperature changes associated with these leaks are below the resolution of conventional logging tools, including spinners, temperature logs, down-hole cameras, and noise logs. These tools are even more limited when trying to detect leaks that occur behind tubing. The ultrasonic leak detection tool can identify leaks so small as to be almost unbelievable. Tool Principles and Operation. SPE paper 1028151 details the tool physics and development history of the ultrasonic leak detection log. Tool principles are briefly summarized here. The frequency spectrum a leak produces is a function of differential pressure, leak magnitude, and leak geometry. These properties determine whether the frequency is audible, ultrasonic, or both. The ultrasonic logging tool (Figure 1) utilizes a sensor that detects a frequency spectrum, including those typically produced by leaks. The signal is processed by a series of band-pass algorithms that focus on frequencies in the ultrasonic range. Virtually all audible noise associated with tool movement is filtered out, allowing continuous logging. Typical logging speed is 30 feet per minute (fpm) and leaks can be identified while logging in either an up or down direction. Greater accuracy is achievable due to the characteristics of ultrasound, which attenuates, or dies away, quickly in fluids. Ultrasound typically travels only 3–10 ft in a wellbore before attenuating. This attenuation results in a very sharp leak character, typically identifying the leak within 1 to 2 feet.

Multi-finger calipers have provided an excellent overview of internaltubing condition for the past fifty years. However, understanding the finedetails of pipe condition over short intervals required familiarity andtraining in interpreting the raw curves produced by these tools. Thedevelopment of digital caliper data and 3D visualization software hasdramatically altered pipe condition evaluation at Prudhoe Bay, Alaska. 3D visualization software allows the average engineer to quickly andaccurately understand the details of localized tubing damage. Additionally, computer processing of digital caliper data supports quick correlation oftubing damage to wellbore geometry, other leak detection logs, previous caliperdata of the same well interval, and cross-correlation of data from differentwells. This has resulted in dramatic improvements to recent wellwork decisions, allowing surgical placement of patches, plugs, and whipstocks. Caliper logshave been used to assess scale buildup prior to coiled tubing scale removaloperations and have been run after removal to evaluate job effectiveness.Additionally, areal corrosion trends and velocity effects have been identified, resulting in recommendations to deter damage. This paper presents several examples of how 3D visualization software hasled to improved wellwork operations based on a study of approximately 500calipers run in the Eastern Operating Area of Prudhoe Bay, Alaska. Introduction Multi-finger caliper tools take measurements of slight changes in tubulardiameter when the fingers come in contact with its surface (Figure 1).Mechanical calipers were originally designed in the 1950's to monitor tubingcorrosion. Real-time digital calipers were developed in the 1990's to monitorcasing wear during drilling operations, dramatically improving on this concept.Since the advent of the digital electronic caliper, analysis techniques havecontinued to evolve into increasingly powerful surveillance tools. History of calipers at Prudhoe Bay, Alaska. Calipers have been usedto inexpensively assess internal pipe condition at Prudhoe Bay for over 25years. Prior to the advent of digital calipers, tabulated reports weregenerated along with the traces of each caliper finger. These "squiggles" (Figure 2) could not be interpreted without significant training and theengineer relied on the caliper company's representative for in-depthanalysis. The introduction of memory multi-finger digital calipers dramaticallyaltered tubing and casing evaluation at Prudhoe Bay. Detailed analysis can nowbe easily performed with software that requires minimal training to use. Since1999, approximately 1000 slickline and coiled tubing-conveyed memory calipershave been run at Prudhoe Bay. Multi-finger imaging tool. Calipers are able to pass through typicaltubing restrictions on a single trip and can record data in the casing stringbelow the tubing, as well as in the tubing itself. The measurements have aresolution of a few thousandths of an inch, an accuracy of +/-0.01 inch, andare not affected by wellbore fluids. Currently, there are four different caliper configurations that can be usedto log various ranges of pipe sizes in a single run. These include conventional40-finger, 2–3/4" OD tools which can log 4–1/2" through 7" pipe sizes, andextended reach versions of the same tool that can reach out to include9–5/8" pipe. Smaller, 1–11/16" OD, 24-finger tools are available in aconventional configuration to log 2–3/8" through 4–1/2" tubulars and inan extended reach configuration to log 2–3/8" through 7" tubulars. While most of these options have been available since late 1999, the40-finger extended reach capability is specific to a new generation of tools.These tools became available in 2006 and can work simultaneously withproduction logging and other diagnostic logging tools. In Prudhoe Bay, thesenewer generation calipers have been run simultaneously with magnetic thicknessinspection tools.

Summary When operators are faced with well-integrity problems, a variety of methods may be used to detect the source of annular communication. Methods for detecting downhole leak points include spinners, temperature logs, downhole cameras, thermal-decay logs, and noise logs. However, many of these methods are ineffective when dealing with very small leaks and can result in collected data that require a significant amount of logging finesse to interpret. Ultrasonic listening devices have been used for a number of years to detect leak sources effectively in surface production equipment. Ultrasonic energy has some properties that, when compared to audible-frequency energy, make it ideal for accurate leak detection (Beranek 1972; Povey 1997; Evans and Bass 1972). Like audible-frequency energy, ultrasonic energy can pass through steel. However, ultrasonic energy propagates relatively short distances through fluids when compared to equal-energy audible-frequency sound. Thus, when an ultrasonic signal of this nature is detected, the detection tool will be in close proximity to the energy source. On this premise, an ultrasonic leak-detection tool was developed for downhole applications to take advantage of the unique properties of ultrasonic-energy propagation through various media. Data-acquisition equipment and filtering algorithms were developed to allow continuous logging conveyed on standard electric line at common logging speeds. Continuous logging has proved to be significantly more efficient in locating anomalies than static logging techniques commonly used in noise-logging operations. During development, the tool was shown to be effective in locating leaks as small as 0.026 gal/min with an accuracy of 3 ft in production tubing, casing, and other pressure-containing completion equipment. Leaks also have been detected through multiple strings of tubing and casing. The tool has proved to be effective in locating leaks that other diagnostic methods were unable to locate.