Maintaining healthy well integrity in heavy-oil thermal wells is a challenge. Steam causes significant variation in temperature along the wellbore resulting in excessively high stresses that can result in parted casing or even a complete casing failure. Determining casing break/failure condition is an important part of managing thermal well integrity. Identifying potential risks based on findings from electromagnetic (EM) casing inspection logs is essential to plan mitigation actions. EM casing inspection logs can also be run prior to putting wells on steam injection to establish a baseline and regularly evaluate well integrity via a time-lapse methodology. In this paper, we have outlined the successful application of Pulsed Eddy Current (PEC) Electromagnetic casing inspection technology in thermal well integrity. One of the major benefits of PEC casing inspection technology is a reliable method to locate casing breaks. It provides casing inspection without retrieving tubing (first pipe) that saves time and costly workover. This paper briefly explains the PEC technology, how it has been deployed, and the methodology developed to quickly and clearly identify casing breaks because one of the evaluation challenges is that the typical thermal casing break occurs in the vicinity of the casing collar. We have demonstrated in the paper validation of the PEC technology for detecting casing breaks. It includes downhole comparison with a traditional multi-finger caliper log after the tubing is pulled. The paper includes some case study examples of how PEC has been used to successfully identify casing breaks and conclude with a summary collected over five years of PEC application with a 100% success rate in more than 200 Canadian heavy oil wells.
New sensors have been developed for measuring in-situ fluid density that are based on the natural vibration of a structural member in contact with fluids being sampled using a wireline pumpout formation tester. Typically, a fluid-conveying tube is driven to its natural frequency and the frequency changes with fluid density. This design has the potential to greatly enhance the downhole fluid density measurement capability. However, the physical characterization and subsequent calibration of the sensor had to be proven for the harsher downhole environment. Although the principle for the vibrating density sensor is simple, a long list of factors, such as temperature, pressure, and tension, directly or indirectly affect the response of the sensor. Experimental correlations are typically used to calibrate this type of sensor. However, in this paper, we systemically study all of these factors and derive a differential equation that fully describes the physics of the vibrating tube densitometer based entirely on first principles. This is followed by the solution of the equation and its subsequent application to laboratory test results as part of the sensor calibration process. Comparisons between theoretically predicted density values for various fluids and their known fluid density values show this method to be more robust than previous correlations methods. An accuracy of better than +/- 0.002 gm/cm3 over the pressure range of 0 to 20,000 psi and a temperature range of 75 to 350° F under controlled conditions is achievable. The resolution of the sensor can also be better than 0.001 gm/cm3. Experimental results and field examples are presented to demonstrate the accuracy and resolution of the sensor. Introduction A pumpout wireline formation tester (PWFT) is a tool routinely used by operators to collect pressure, volume, and temperature (PVT) reservoir fluid samples. Among the long list of sensors included in the PWFT, the in-situ fluid density sensor plays crucial roles because an accurate determination of the formation fluid density under reservoir conditions is one of the fundamental objectives of formation evaluation. The importance of accurate density is reflected in the number of applications in which in-situ density is essential, such as pressure gradient analysis, fluid contacts, zonal compartmentalization analysis, delineation of oil-water transition zones, contamination analysis during sampling, and fluid identification analysis for immiscible fluids. Pressure gradient analysis based on PWFT pressure surveys has long been a fundamental method of determining fluid types because the in-situ moveable fluid density is directly related to the fluid type. However, there are well-known inherent uncertainties associated with errors in the gradient as a result of inaccuracy in the depth and pressure measurement (Collins et al. 2007). Furthermore, complications in the wellbore environment, such as invasion, supercharging, depletion, formation wettability, and capillary pressure effects (Desbrandes et al. 1988 and Carneigie 2007) combine to introduce additional errors. Therefore, although the practice of using pressure gradient has been one of the primary methods of determining fluid density since its introduction in the 1970s (Pelisser-Combescure et al. 1979), a direct in-situ measurement of fluid density that can overcome these complications is still highly desirable. Various methods have been adapted for density measurement (Godefroy et al. 2008). There are currently two types of sensors for in-situ downhole fluid density measurement; both are based on the principle of measuring the resonance frequency of a vibrating member in contact with fluid. One type has one or more vibrating elements submerged in the flow line (O'Keefe et al. 2007). The disadvantage of this type of sensor is its limited volume of investigation. Although the sensor is fully immersed in the fluid stream, it is sensitive only to a boundary layer in the immediate vicinity of the vibrating sensing element. Thus, it may inherently have problems in measuring multiphase liquids (Webster 1999).
Well integrity management is a prime global focus area for all oil and gas operators. Any field-wide corrosion challenge requires a substantial investment to manage the integrity of assets and, consequently, to maximize life expectancy and efficiency. Over decades, the industry has concentrated its efforts toward containing fluids from any unintentional release at the surface occurring as a result of corrosion. This paper highlights the most recent electromagnetic (EM) logging technology developments to address well integrity challenges. Three primary corrosion mechanisms occur in oil and gas wells: chemical, mechanical, and electrochemical. Electrochemical corrosion is the mechanism responsible for most of the failures in which the outermost casing is exposed to corrosive fluids and is consequently penetrated first. As the corrosion process continues, subsequent well barriers are progressively corroded until the inner casing or tubing is in direct contact with a corrosive environment and at direct risk of a major well integrity failure. As a result of this outside-to-inside corrosion mechanism, the early diagnosis of the outermost casing status is especially important as a proactive measure to identify any potential weak zones in the completion string. This early diagnosis is a major step to optimize well integrity intervention and to optimize workover operations costs. Cathodic protection and coated casing are used to extend the life of the well by controlling corrosion; however, these are only mitigation measures that slow down but do not eliminate corrosion. EM logging technology provides an effective method for monitoring and identifying the effectiveness of these corrosion mitigation measures. Time domain EM pulse eddy current (PEC) technology has facilitated corrosion evaluation by logging through tubing, thereby avoiding the cost of pulling completions solely for surveillance purposes. The latest EM PEC technology, the enhanced pipe detection tool (ePDT), provides individual barrier thickness measurements for four concentric pipe strings. The innovative features of ePDT include: (1) A fractal transmitter (Tx) coiled array that improves the performance of the tool with enhanced signal-to-noise ratio (SNR) covering a wide signal dynamic range, and adaptability for various logging speeds and spatial resolutions for varying pipes; (2) a synthetic aperture of the receiver (Rx) coil array for noise compensation from extraneous tool motion; and (3) a wide-spatial aperture Rx coil array which, when combined with (1) and (2), enables the compression of the inner pipe remnant magnetization interferences without sacrificing spatial resolution. This paper demonstrates ePDT benefits by benchmarking to other technologies and control environments. The results are discussed in detail to provide an overview of EM technology, as well as the advantages and limitations. Ultimately, the answer product from this technology is integrated with other current and historical information related to the well or field being evaluated as part of the well integrity management system (WIMS). Finally, it is important to expand the technology operating envelope beyond the standard applications to address larger completions challenges, such as gas wells and landing base inspection, by extending the tool capabilities while optimizing data acquisition and processing methodologies.
With the increased demand of Hydrocarbons, the industry trend to continually develop the unconventional reserves and/or maximize the HC production; different wellbores are accordingly drilled and completed with multi-stage completions. Frac Sleeve in Multi Stage completion tend to show several integrity issues. Multi-finger caliper tool has a proven capability of assessing the wellbore obstructions and internal corrosive damage to tubulars. Gathering appropriate logging data is important for monitoring well-head and annuli pressures. Evaluating the Frac sleeves integrity whether are closed or open as well as to look for deformation within the sleeves are of client's objectives to confirm its conditions. We will combine the caliper data with passive noise detection tools to confirm and understands the fluid flow behavior in the well-bore and behind casing. Same combination is used to assess the injection sweep efficiency and anisotropy. Caliper 3D visualization and advanced noise detection processing software were used to quickly and precisely understand the condition of the Frac sleeves in several wells for the sake of injection assessment and for future remedial actions to the recommended sleeves. Also, through comprehensive analysis, caliper logs have been used to assess scale buildup, paraffin or other mineral deposits in the wellbore which could coat the perforations, casing, tubulars, valves, pumps and downhole equipment. The proposed paper will summarize field results and data gathered from several passes across the Frac sleeves. Using the logging data, we will measure the effectiveness and integrity of the Frac Sleeve for the purpose of injection/production assessment.
Significant drilling challenges can exist when drilling in mature fields or in reservoirs that are subject to various geomechanical stress regimes associated with overpressure, tectonic stress, and depletion. Despite mitigation efforts to reduce stuck-pipe occurrences, drilling problems leading to stuck pipe still occur. When conventional techniques used to free the drillstring are ineffective, wireline logs are often run to determine the stuck depth of the drilling assembly and to release the pipe above the free point.The traditional free-point (FP) logs used to determine the depth of stuck pipe are based on a measurement of strain when stress is applied to the pipe between two points. These measurements are taken at specific intervals and require the tool arms to firmly grip the pipe to prevent movement that could mask the strain measurement. This simple method is difficult to implement reliably. Because it depends on the skill of the specialist operator, pipe-recovery operations include "more art than science." A new technology, based on electromagnetic measurements, can now make a continuous FP log. The log consists of two passes, with and without stress applied to the pipe. By comparing the two responses, service company specialists and drilling engineers can interpret the log without the need for highly-experienced personnel.This paper reviews several cases from the Middle East and provides information about the tool response in various parts of the drilling assembly. It also reviews pipe-recovery techniques that are recommended depending on the FP log response and the specific drilling assemblies, such as drill collar, drill pipe, crossovers, and jars. The pipe-recovery techniques discussed include explosive back-off techniques, explosive pipe severing, and various pipe cutters. The case study examples demonstrate the improved efficiency and reliability of determining stuck-pipe intervals and subsequent successful pipe recovery.
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