Fill cleanouts, matrix stimulation, cementing, and downhole milling are some common coiled tubing (CT) operations. The difference between the success and failure of these jobs relies heavily on the knowledge and prediction of the behavior of downhole parameters such as temperature and pressure. Another significant percentage of CT operations depends on highly accurate depth control to ensure the intended result of the operation. These depth-critical operations include setting packers, tubing patches, CT-conveyed perforating, and zonal isolation. And in virtually all CT operations, including fill cleanouts, stimulations, and cementing, the knowledge of an actual tied-in depth is advantageous to operations. The purpose of this paper is to present a simple and reliable system that allows real-time monitoring of downhole pressure and temperature, and provides depth correlation using a casing collar locator (CCL). In this system, the downhole parameters are recorded in real time without the limitations of conventional wireline-enabled coiled tubing units. The information presented in this paper summarizes the operations performed during the field-testing of the system at Alaska's North Slope. Twenty-seven CT operations were successfully performed using the system; this demonstrated its reliability and provided the crew with the information needed to improve the efficiency of the operations being performed. The system comprises three main components: Introduction Most CT operations have a common challenge: to evaluate and control each stage of the job through educated guesses of what is happening downhole based on surface data and feedback. Downhole pressure is estimated from pressure readings at the pump, wellhead, or both. Actual tool depth is inferred from the amount of coiled tubing going in the hole, with errors as high as 0.3% being accepted as common. Different methods are used to determine the actual depth depending on the depth accuracy required for any individual job. These methods include tagging a known bottom or restriction, use of tubing tail locators, running a memory logging tie-in and flagging the CT, and running mud pulse telemetry logging tools. These techniques can be time consuming, expensive, or add complications to the operations. The effect of actual downhole temperature on day-to-day coiled tubing operations is not completely understood but is believed to be negligible, with the marked exemption of cementing operations, mainly because there is no practical way of monitoring it to study actual values and changes while operations are underway. The use of an e-line enabled Coiled Tubing unit can overcome these challenges1, but it introduces limitations, such as significantly higher cost and maintenance requirements, limited fluid compatibility, and flow area restriction within the CT. These limitations effectively reduce the range of possible CT operations that could benefit from real-time downhole readings. Although there have been significant technology advancements since loggin operations with a CT unit started in the early eighties---notably in the connections, weak points, and understanding of "slack wire management"---the general principle has not changed. Information is acquired using downhole tools. The information is then transmitted uphole via an electric cable that also doubles as a power conduit for the tools. A collector ring assembly is then used to transfer the information out of the coiled tubing reel and into the logging unit, without restricting CT movement. The final link is a depth encoder signal sent to the logging unit to enable information to be recorded in a conventional method. New fiber optic manufacturing processes using advanced alloys and advances in wireless communication capabilities present the oilfield with new opportunities and novel ways of tackling existing challenges. Many of these advances have been incorporated in the development of the acquisition system presented in this paper.

Cementing through coiled tubing electric line (CT e-line) is not a common practice; this application is highly recommended in Coiled Tubing Drilling (CTD) applications using the existing CT e-line pipe to achieve a better time performance for sidetracking a well since using the CTD technique is mainly based on economical evaluation. Several considerations need to be taken into account while designing the job and performing the operation. The relatively high density and viscosity fluid can lead to bird nesting the cable due to high friction and excessive slack inside the pipe; it can also affect the integrity of the cable as well as the performance of the bottomhole assembly (BHA). The interface between cement and other fluids pumped through CT e-line pipe can be also affected. A review on a feasibility study of cementing through CT e-line that was performed in 2003 in Alaska highlights all the concerns, challenges, and potential issues that can be encountered during a cementing job through CT e-line, best practices, lessons learned, and way forward to implement this technique. This review is supported by two successful case histories performed in Malaysia CTD campaign applying this technique for different objectives: remedial cementing for casing and tubing sealing in a deviated well and remedial cement plug for window recovery. By implementing cementing through CT e-line, the effective job time was improved by avoiding swapping pipes in an offshore environment where the logistic, safety, and space accommodation is a huge challenge. The use of CTD as an economical sidetracking technology was reinforced by making the CT e-line pipe universally utilized in all the project steps, even for running and setting completion.

For many years perforating in horizontal wells under variable conditions has been one of the biggest challenges in the South China Sea area. Being a critical step during the cycle of a well, operators have to identify the best perforating method to achieve desired results in the safest manner whilst remaining cost-effective. Perforating using coiled tubing (CT) conveyance provides a range of flexibility as an attractive method to convey long sections of guns in a single run; however, whether this technology can be considered the most appropriate solution in light of available alternatives developed in recent years, remains in question. One of the operators in Malaysia faced this situation when preparing its first perforating campaign in a field with complex extended reach wells, where the main target was to produce the maximum quantity of gas available whilst avoiding sand production. The campaign was performed with a rig present and any delay due to failure meant a huge cost impact. The operator solicited a detailed technical design and a systematic evaluation of all available options in the market to perforate the pay zones successfully. The solution implemented was based in part on the experience obtained during previous years in the Area, where different methods were used. An exhaustive statistical analysis was performed to determine the critical parameters to be the focus of the design and the selection of the most reliable technology to address the various scenarios that the campaign presented. Hydraulically actuated CT tractors, friction reducers, sterling beads, and creative use of buoyancy effect, together with using state-of-the-art CT technology were among the combinations proposed to overcome CT lockup and successfully convey the oriented guns to total depth (TD) in all wells. The intent of this paper is to provide a strong guide to CT perforating under variable conditions in horizontal wells through a thorough requirements analysis, risk evaluation and proper selection of technology. A review of the results and lessons learnt are also included. The engineering process, which has since become the benchmark in the area, can be applied with confidence as evidence by the success of the campaign.

Coiled tubing (CT) sand cleanout has been a normal practice for offshore wells, and repeated cleanout runs will have to be done over the years to sustain production. It has been observed that the production period of these offshore wells has shortened significantly after each cleanout due to sand particles loading up in the production tubing at a faster rate. This production trend is typical for wells with no downhole sand control in the original completion. Various aspects in terms of well design and reservoir conditions have significantly increased the complexity of sand cleanout. This, for example, includes the large 9 5/8-in. casing section with small dual upper completions of 2 7/8-in. production tubing, a high angle with a long horizontal section, and severely drawn-down reservoirs. There were also previous findings on the well where cement pebbles were found on the production choke at surface contributing to higher risk during intervention. An integrated engineered solution was brought forward to successfully execute the CT sand cleanout job by capitalizing on both engineering and operational efficiencies. In terms of technical and engineering design, real-time fiber-optic downhole telemetry system, nitrified cleanout with a shear-thinning gel fluid that has superior suspension ability, and a milling tool for cement pebble cleanout were utilized. Operationally, an electrical submersible pumping (ESP) system capable of providing continuous supply of seawater and custom-built skidding beams for sand screen deployment purposes were also introduced for the first time for CT operations in southeast Asia that successfully improved operational efficiency and job safety. A remedial sand control solution was also used to improve production longevity after sand cleanout, without doing any major pull-tubing workover or sidetrack drilling. Either through-tubing sand screens or a sand agglomeration treatment technique was carefully chosen and deployed to address the sand load-up issue in these wells. This paper discusses the operations, challenges, and the key success factors that have contributed to a well-engineered CT cleanout and deployment of sand screen and sand agglomeration treatment.

This paper shares the best practices for performing coiled tubing (CT) operations in high-temperature geothermal wells with major challenges such as live well challenges, scaling of pumping fluid, high surface temperatures causing damage to wellhead stack, and CT tag issues. Some geothermal wells have very high bottomhole temperature (BHT) of 550 to 600 °F and surface temperature of 350 to 400 °F, which possess many service quality and health, safety, and the environment risks. With limited CT geothermal interventions as compared to conventional operations, performing live well CT interventions can be highly risky. Because commonly available pressure control equipment (PCE) seal material is rated to 250°F, the biggest risk is damage to the surface CT equipment, which may result in a well control situation. Generally, the lead time is high, and it is expensive to use temperature seal material rated more than 250°F. A generalized design methodology was developed to check the CT job feasibility in a high-temperature geothermal well. To gain further understanding on the same, three cooling loop designs are compared in this study. Then, the best solution was simulated, implemented, and verified on some wells of "X" field. This design proved to be effective operationally and has reduced the risks for steam inflow into the PCE. For the case of scaling caused by pumping fluids at high temperatures, this was identified while performing CT operations in geothermal wells of X field. The scale deposited on the CT along with pumping fluid was sent for laboratory hardness and solubility analysis. The results were compared, and lessons learnt to prevent any scaling are discussed. Most of the geothermal wells are completed with a large-diameter completion (7-in., 9.625-in., and higher), which has a bigger flow area to accommodate high steam inflow. Using even a 2.875-in. CT in these wells presents issues of CT tagging at the completion-liner interface, lower annular velocities, and lifting capacity, among others. The best practices were developed on the job to identify the most efficient bottomhole assembly (BHA) design, reducing the probability of CT getting tagged at these depths.