Cleaning sand fill out of large diameter, deviated wellbores with low-bottom-hole pressure has proven to be a major challenge. During a conventional coiled tubing cleanout on these lower reservoir wells, either a low density fluid, such as diesel, or a nitrified system, is utilized to maintain an underbalanced condition during the cleanout process. It is common that many of these cleanout operations are conducted with limited annular fluid velocities. Sand vacuuming technology addresses these challenges by utilizing a jet pump powered by single phase liquid which carries all of the returns up the concentric coiled tubing (CCT) annulus. Previous field practices indicate that most of the sand/well vacuuming jobs were applied in low-pressure reservoirs, unconsolidated sands with relatively small size solids (less than 20/40 mesh) in horizontal slotted liner completions. There are still some challenging issues for sand vacuuming operations. These include the use of heavy coil in coil strings, limited jet pump capacity for deep, extended reach wells, vacuuming large particulates through the narrow flow intake to the concentric coiled tubing annulus, and breaking consolidated sand bridges with limited forward flow jetting. This paper discusses the modification of a previous jet pump with a three-way switch tool (sand vacuum, well vacuum and jetting mode) to clean large size proppant (8/14 mesh). The modified bottom hole assemblies were tested in a full scale flow loop. The flow loop setup and test results will be discussed. The distance of the rear facing jets to the intake of the jet pump and the pull-out-of-hole speed of BHA are crucial to insure the sand can be completely removed. A few field cases are also discussed in this paper. Both flow loop tests and field operations indicate that a proper designed jet pump with a jetting switch tool could effectively vacuum the larger proppant in low pressure extended reach wellbores. Introduction Performing sand cleanouts remains one of the top uses for coiled tubing. Though sand cleanouts are very common, the actual processes are often very difficult. Wells with ultra low bottom hole pressure reservoirs are extremely challenging for conventional CT cleanout methods to succeed1. These low success rates lead to the development of concentric coiled tubing. The use of concentric coiled tubing (CCT) to power a modified downhole jet pump for solids removal has been utilized since the mid 1990s2. Hundreds of successful cleanouts have taken place3–16, primarily in horizontal, low reservoir pressure oil wells containing formation fines. The system incorporates coiled tubing inside of coiled tubing, with typical combinations consisting of 2–3/8" outer string with 1-¼" inner string, 2" × 1", or as small as 1- ½" by ¾". This system allows the cleanout to be performed with single-phase fluid only, significantly simplifying logistics and costs when compared to circulating nitrified fluids during a conventional cleanout11. Since inception of the sand vacuuming technology, multiple iterations of the downhole tool system have been employed. Initial applications were conducted with a 3-¾" BHA2–8 and were focused mainly on horizontal, slotted liner completions with 2000 ft TVD /7200 ft measured depths. In the past several years, additional challenges have been faced, such as smaller completion sizes, deeper TVD/MD wells, lower reservoir pressures, tougher sand bridging, and larger particle sizes. These challenges led to enhanced design changes that broaden the operating envelope for the use of the sand vacuuming system. The modern versions of the BHA are available in 2–1/2", 2–1/8" and 1-¾" outside diameter9,12 and incorporate multiple operational modes to ensure cleanout efficiency. Additionally, the end of the sand vacuuming system may be equipped with a supplementary tool to broaden the work scope13. Such tools as lateral entry guidance systems, rotating jetting tools, etc., have been incorporated into the sand vacuuming system.

fax 01-972-952-9435. AbstractThe removal of solids from the Tyonek field gas wells has proven to be a major challenge for the operator.The field has an exceptionally low bottom hole pressure gradient of ~0.1 psi/ft. This means that traditional two phase sand removal operations using coiled tubing had not been successful. Even following the development of engineered cleanouts, the bottom hole pressure was just too low to support economic returns.The option of reverse circulating would also not be feasible due to the massive quantities of nitrogen required to succeed.Following reviews, the most efficient method of cleanout was identified as using a Concentric Coiled Tubing Vacuum Technology (CCTVT) system. The CCTVT essentially provides a second annular return route for wellbore solids while simultaneously boosting the return pressure. This permits the cleanout to be performed with fluid only, a significant logistical and financial saving over two phase operations. This paper will describe the system technology, engineering planning, well control considerations, system limitations and the observed operational and production results of a five well campaign from the first CCTVT operations conducted in Alaska as well as the first application on an offshore platform.

fax 01-972-952-9435. AbstractThe removal of solids from the Tyonek field gas wells has proven to be a major challenge for the operator.The field has an exceptionally low bottom hole pressure gradient of ~0.1 psi/ft. This means that traditional two phase sand removal operations using coiled tubing had not been successful. Even following the development of engineered cleanouts, the bottom hole pressure was just too low to support economic returns.The option of reverse circulating would also not be feasible due to the massive quantities of nitrogen required to succeed.Following reviews, the most efficient method of cleanout was identified as using a Concentric Coiled Tubing Vacuum Technology (CCTVT) system. The CCTVT essentially provides a second annular return route for wellbore solids while simultaneously boosting the return pressure. This permits the cleanout to be performed with fluid only, a significant logistical and financial saving over two phase operations. This paper will describe the system technology, engineering planning, well control considerations, system limitations and the observed operational and production results of a five well campaign from the first CCTVT operations conducted in Alaska as well as the first application on an offshore platform.

The latest growth of North American unconventional shale plays is supported by the shift towards improved well designs: extended well laterals, high-intensity proppant loadings, and adoption of slick water fluids for fracturing. To optimize well productivity and economics, producers continue to push the well lateral boundaries from 10,000-ft to over 15,000-ft, creating super lateral wells, which pose significant challenges and pushed the boundaries of extended reach Coiled Tubing (CT) operations. This document outlines field operational details, string design and downhole tool considerations that had a major effect on the success of extended reach CT interventions in super laterals with 2.375-in CT diameters. Currently, several U.S. operators have succeeded with 7,500-ft to 10,000-ft range laterals using CT in post-fracture plug mill-out and clean-out operations. These well designs and successive service operations require larger CT diameters and higher pumping pressures to effectively complete job objectives. Generally, 2.375-in CT diameters of over +23,000-ft in length, that feature a robust wall design and materials are being used to withstand the combined pressure loadings and access target depths, –while minimizing bend cycle fatigue accumulation and deformation during operations. Operational plans comparing CT forces, lock-up behavior and hydraulics analysis, along with friction matching of post-job data evaluations, were used to compare the CT performance in the newest well lateral records. Other operational factors, such as equipment availability, logistical issues, and field deployment, are also considered in the analysis of using CT in these complex wells. Field results demonstrated that CT well interventions in over 14,500-ft laterals are feasible by using highly engineered 2.375-in CT, friction reduction tools accompanied by fluids chemical additives, and tailored operating techniques that improve efficiencies. The application of high strength quench and tempered material with specific wall configurations that feature the use of the thickest gauge used in a working CT string, and the newest taper technology that transitions through four nominal wall thicknesses within couple hundred feet, –have been found to maximize lateral reach capabilities and service life in extended reach operations. The inclusion of the latest technologies on extended reach tools and fluid additives is a must to maximize friction reduction and wellbore cleaning at rates of over 4 BPM and working pressures of over 7,000 psi. These industry records demonstrate that the potential for longer laterals is far from being exhausted. Technological innovations on surface equipment, downhole tools, CT materials and highly engineered strings configurations, along with refined operational practices and logistics, are required to perform safe extended lateral completions on a larger scale.

Well completions in the United States are predominantly completed using the plug and perforate process. Following the fracture stimulation treatment, coiled tubing (CT) is utilized to convey a downhole milling assembly to remove these plugs and clean out the wellbore. As wells continue to extend in lateral length, an extended reach tool (ERT) is commonly used to aid in achieving these depths. In order to truly understand the milling process using an ERT, a downhole memory tool was developed. The memory tool is run in-line with the milling assembly and obtains weight on bit (WOB), torque, pressure, temperature, and vibration at one second sampling rates. The tool has been run on multiple bottom hole assemblies (BHA) on both 2 3/8-in and 2 5/8-in CT on over 35 jobs accounting for 1,500 composite frac plugs. The data collected is compared to surface data providing a detailed view of the overall plug milling operation. The ERTs used provide WOB while milling at a level that is unpredictable by commercial CT modeling software. Comparison of the surface weight gauge with the downhole WOB enables a clearer understanding of the forces delivered by the ERT. This data provides an avenue for better job planning and informed decisions on ERT selection.