Academic literature on the topic 'Tubing movement'
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Journal articles on the topic "Tubing movement"
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Yohana, E., and Indra Sakti Rahyang. "Tubing Movement Analysis in Completion Process at Well X." International Journal of Multidisciplinary Research and Analysis 05, no. 10 (2022): 2706–16. http://dx.doi.org/10.47191/ijmra/v5-i10-21.
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The completion process in oil and gas production is one of the most important steps and affects to the final result of the entire process. In actual conditions, many things must be considered in the completion process. One of the most important things is about tubing movement. Tubing movement is the movement of tubing caused by differences in pressure and temperature in the well. Tubing movement can cause deformation of the tubing structure, and if the selection of tubing and packer is not appropriate, it can cause damage to the tubing or well structure. Calculating tubing movement can be done by calculating the total movement and force generated by this four tubing movement effects, which is: temperature effect, ballooning effect, buckling effect, and piston effect. The case study analyzed in this proposal is horizontal well X, and has a total tubing movement of 13,48 in elongation, or produces a force of 47.864,36 lbs. Because the value is positive, the force that applies is the compression force. By knowing the total force and displacement generated by the tubing movement, the engineer can design what type of packer will be used. For the case study in this report, it can be concluded that a force of 47.864,36 lbs can still be resisted by tubing which has a body yield strength specification of 361.000 lbs. Therefore, the tubing can be design to use a no slip packer where there is no movement between the tubing and the packer.
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E., Yohana, Sakti Rahyang Indra, Naufal Fajar Pramudya dan, Bahar Shofwan, and Syaiful. "Tubing Movement Analysis in Completion Process at Well X." International Journal of Multidisciplinary Research and Analysis 05, no. 10 (2022): 2706–16. https://doi.org/10.5281/zenodo.7185117.
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The completion process in oil and gas production is one of the most important steps and affects to the final result of the entire process. In actual conditions, many things must be considered in the completion process. One of the most important things is about tubing movement. Tubing movement is the movement of tubing caused by differences in pressure and temperature in the well. Tubing movement can cause deformation of the tubing structure, and if the selection of tubing and packer is not appropriate, it can cause damage to the tubing or well structure. Calculating tubing movement can be done by calculating the total movement and force generated by this four tubing movement effects, which is: temperature effect, ballooning effect, buckling effect, and piston effect. The case study analyzed in this proposal is horizontal well X, and has a total tubing movement of 13,48 in elongation, or produces a force of 47.864,36 lbs. Because the value is positive, the force that applies is the compression force. By knowing the total force and displacement generated by the tubing movement, the engineer can design what type of packer will be used. For the case study in this report, it can be concluded that a force of 47.864,36 lbs can still be resisted by tubing which has a body yield strength specification of 361.000 lbs. Therefore, the tubing can be design to use a no slip packer where there is no movement between the tubing and the packer.
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Sun, Wei, Guo Xiang Meng, Qian Ye, and Wen Hua Xie. "Modeling and Simulation of Pneumatic Impactor for Tubing Plugging." Advanced Materials Research 201-203 (February 2011): 2174–77. http://dx.doi.org/10.4028/www.scientific.net/amr.201-203.2174.
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Tubing plugging often occurs and brings some difficulties to industrial production. This paper proposes a simple pneumatic impactor which can instantaneously generate great acceleration by a reservoir to shock and smash calcium monohydrate bonding in the tubing inwall. The working principle and the mathematical model of the impactor are introduced in detail. In order to obtain its dynamic characteristic, the simulation is performed. The results show that during the movement of the piston back pressure occurs due to the outlet chamber squeezed by the piston with a high speed, and with inlet pressure increasing positions of the piston with different peak velocities are almost the same. This impactor can be used to unplug tubings in oil or gas well.
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Wang, Lei, Zheng Chu, Jiang He, Yujia Zhai, Junming Huang, and Haonan Yang. "Numerical Simulation Study of the Optimization on Tubing-to-Sediment Surface Distance in Small-Spacing Dual-Well (SSDW) Salt Caverns." Processes 13, no. 2 (2025): 322. https://doi.org/10.3390/pr13020322.
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The small-spacing dual-well (SSDW) technique plays a crucial role in the establishment of underground salt cavern gas storage reservoirs. However, during the cavity dissolution and brine discharge processes, insoluble sediment is prone to being carried into the discharge tubing with the brine, leading to tubing blockages or clogging, which disrupts injection and withdrawal operations and severely affects both project efficiency and the safety of the gas storage facility. This study systematically analyzes the influence of the gap between the injection and discharge tubing and the surface of the sediment-on-sediment movement, deposition, and tubing safety in SSDW salt caverns. Through numerical simulations, this study investigates the influence of tubing layout on the internal flow field distribution of the cavern and the suspension behavior of sediment, revealing the changing trend of the risk of sediment entering the tubing at different distances. The results show that a rational tubing distance can significantly lower the risk of sediment backflow and tubing entry, while maintaining high brine discharge efficiency. Based on the simulation results, an optimized tubing layout design suitable for SSDW salt caverns is proposed, offering technical direction to guarantee the safe and effective functioning of underground salt cavern gas storage sites.
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Makarenko, V. D., A. V. Liashenko, and О. Yu Vytyaz. "The technology of cleaning tubing from hydrate-resin-paraffin deposits." Oil and Gas Power Engineering, no. 2(36) (December 29, 2021): 80–87. http://dx.doi.org/10.31471/1993-9868-2021-2(36)-80-87.
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During the operation of oil and gas wells there is a constant decline in production. The reason may be various factors, such as the reduction of the internal space of the tubing due to the deposition of hydrate-paraffins, asphaltenes, resins and mineral salts. To prevent and clean these deposits, various control methods are used: the use of special coatings on the inner surface of the pipes, the introduction into the pumped stream of various chemical reagents, sonication, magnetic treatment, mechanical methods, etc. However, some of them are considered inefficient, economically unprofitable or quickly fail.That is why an improved design of a device for cleaning the inner surface of tubings of oil and gas wells was proposed. The device refers to the equipment of the oil and gas industry, namely as a mechanism for restoring the internal space of well pumps. Calculations for the design of cleaning devices for different diameters of tubing are given. Kinetic calculations of the movement of the cleaning mill in tubing pipes under the action of hydraulic forces were performed. Based on the obtained equations, in the process of design development, the dimensions and shapes of the working (main) and additional (reverse) cutters were calculated, the masses and strength characteristics of structural elements (pins, traverse, cable, bolted joints, etc.) were selected. Provided the necessary rigidity and reliability of the entire cleaning device. Thus, the proposed design developments in combination with the previously known will allow to obtain a new positive effect, which is to improve the quality of cleaning of tubing. Industrial tests of the developed design on objects showed significant advantages in comparison with domestic and foreign analogs.
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Karlik, John F., J. Ole Becker, and Ursula K. Schuch. "022 Delivery of Gases to the Soil Matrix via Buried Drip Irrigation Tubing." HortScience 34, no. 3 (1999): 444E—445. http://dx.doi.org/10.21273/hortsci.34.3.444e.
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The impending worldwide restrictions on the use of methyl bromide (MeBr) as a soil fumigant have prompted an intensive search for more-effective methods for delivering MeBr or replacement compounds. Although the majority of agrochemicals are applied in the solid phase or the liquid phase at ambient pressure and temperature, some chemicals, including certain soil fumigants such as MeBr, are gases under normal field conditions. Experiments were conducted to evaluate use of two types of commercial drip irrigation tubing to deliver gases to nontarped planting beds. Air moved through each tubing type immediately after burial; water was not necessary for inflation. Air was also able to move through 40 m of buried rigid drip tubing and through 90 m of buried flat tape that had been used for subsurface drip irrigation for more than 1 year. Mixtures of known ratios of propane and air were introduced into the buried tubing over several time intervals to evaluate gas movement from buried drip tubing into the surrounding soil matrix. Samples were collected from sets of three soil gas sampling tubes placed 15, 30, and 45 cm to the side of the buried tubing and at regular intervals along the length of the tubing, and propane concentrations were quantified by gas chromatography. Tubing lengths and run times affected the magnitudes and uniformity of propane concentrations. Results suggest gas-phase chemicals can be delivered via buried drip-irrigation tubing, but effective distances from the point of introduction will be limited by the low densities and viscosities of gases, and corresponding high rates of escape through tubing emitters.
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Ishmuratov, Timur A., Rif G. Sultanov, and Milyausha N. Khusnutdinova. "Diagnostics of the location of damage to tubing oil well pipes." Tyumen State University Herald. Physical and Mathematical Modeling. Oil, Gas, Energy 5, no. 4 (2019): 115–28. http://dx.doi.org/10.21684/2411-7978-2019-5-4-115-128.
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The study is devoted to the mathematical description of the process of oil outflow in places of leakage of the tubing string, which allows a computer to locate a leakage in the tubing. The authors propose methodology for identifying defects in the tubing and determining the location of the leak. The uniqueness of this methodology lies in quick determination of the place of leakage without the use of specialists, sophisticated and specialized equipment. Mathematical modeling of oil flow in the tubing requires the apparatus of continuum mechanics. It is a general belief that the movement of oil in the pipe flows at low speeds due to its outflow from the hole. Using the general equations of mass and energy balance, the authors have obtained differential equations of fluid motion in a vertical pipe in the process of its outflow from the tubing and in the process of injection. Analytical expressions are the solution to these equations, as they can help in estimating the degree of damage and its location, as well as the feasibility of its eliminating. The results show that an increase in the leakage and injection times leads to improving accuracy of locating damage. Thus, when conducting various geological and technical measures (GTM) at the well, it is possible to assess the presence of leakage and its intensity when deciding on the repair of tubing.
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Shishlyannikov, Dmitry I., Vadim K. Kartavtsev, Dmitry A. Sitnikov, Yuri G. Korotkov, and Anna A. Ivanchenko. "Increasing the operating time of pumping units of water-reducing wells through the use of self-cleaning filters." Bulletin of the Tomsk Polytechnic University Geo Assets Engineering 335, no. 11 (2024): 19–31. http://dx.doi.org/10.18799/24131830/2024/11/4619.
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Relevance. At enterprises engaged in open-pit mining, water-reducing wells equipped with submersible installations of electric submersible pumps are widely used in drainage systems. A significant content of particles of mechanical impurities in the pumped-out well fluid causes intense hydro-abrasive wear of the working stages of the electric submersible pumps. Among the existing methods of combating hydro-abrasive wear of submersible pumps in water-reducing wells, the simplest, most economical and effective is the use of filters of various designs. An urgent task is to increase the operating time of submersible electric submersible pumps while reducing the time and costs for cleaning or replacing filters. Aim. Justification of the designs and operating parameters of a self-cleaning filter and tubing string extension included in the electric submersible pump assembly of a dewatering well. Methods. Static calculations of deformation of the tubing column and the tubing column extension under the influence of overpressure. Results and conclusions. The authors have carried out the analysis of an electric submersible pump functioning in the dewatering wells of quarries during the development of mineral deposits by the open method. It was revealed that the main reason for the failure of the electric submersible pumps is the hydro-abrasive wear of the working stages of the submersible pump. The authors propose a method to increase the operating time of the electric submersible pumps in dewatering wells complicated by intensive removal of particles of mechanical impurities by using a self-cleaning filter of the original design. It is noted that a promising direction of development of the drive for self-cleaning filters is the use of deformation of the tubing column. Based on the calculations carried out, it was concluded that the small depths of dewatering wells cause an insufficient amount of deformation of the tubing string to clean the filter element. To increase the length of the reciprocating movement of the electric submersible pumps relative to the production string of a dewatering well, it is proposed to use a tubing string extension of an original design. The operating parameters of the tubing string extension were calculated, which showed the possibility of providing the required amount of controlled reciprocating movement of the electric submersible pumps in the well to restore the throughput of a self-cleaning filter.
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Shaheed, Luay Hameed. "Analysis and Mitigation of High-Pressure and High-Temperature Well Completion Design of Elkin/Franklin Fields in the North Sea." Journal of Petroleum Research and Studies 12, no. 1(Suppl.) (2022): 1–17. http://dx.doi.org/10.52716/jprs.v12i1(suppl.).617.
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The development of High-Pressure and High-Temperature (HP/HT) wells is accompanied by high risk, and still represents one of the greatest technological challenges for the oil and gas industry related to the equipments used and their ability to sustain these conditions. The results analysis of data is key to investigating reasons for bad performances and failures of well completion design and detecting at an early stage potential downhole events.This paper applies machine learning to the results of real data analysis of deep and deviated well in the HP/HT environment. It presents techniques used to analyze design limits for the tubing string of the well with different rates of production and water injection, and predict pressure and temperature when multiple operations are applied to the tubular string during the well's lifetime. It also analyzes the most important parameters that impact the tubular string, such as temperature effect, safety factors, and tubing length change. A simulation model for a well has been developed to accomplish the objective of this work by using WellcatTM software modules (Prod & Tube) based on real data from the Elgin/Franklin fields in the North Sea. Two designs of tubular string were used to analyze design limits; the first included a tubing size of 4 ½ in and a latched permanent packer, and the second was identical to the first one but included an expansion joint tool to allow free movement of the tubing, and it was used to mitigate the first well completion design failure. Based on the results of this paper, three load cases (produce-6 months, tubing leak, and water injection) failed in the first design when the rates of oil production and water injection were increased to 12000 bbl/d and 5000 bbl/d respectively, whilst all load cases fell into the triaxial envelope and met the axial criteria in the second design. Furthermore, the predicted results of pressure and temperature for the tubing and surroundings indicate the tubular string could be exposed to buckling problems and serious thermal expansion in the annulus. As well, tubing length can be changed (elongated or shortage) owing to thermal effects during multiple load cases.
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Kondrat, R. М., О. R. Kondrat, L. І. Khaidarova, and N. М. Hedzyk. "The Influence of Determining Factors on the Parameters of Gas-lift Operation of Flooded Gas Wells." Prospecting and Development of Oil and Gas Fields, no. 1(74) (March 31, 2020): 72–80. http://dx.doi.org/10.31471/1993-9973-2020-1(74)-72-81.
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The development of gas deposits at the final stage is usually complicated by watering production wells. With the advent of water in the formation product, the gas production rate decreases due to the decrease in the gas-saturated thickness of the reservoirs and the increase in pressure loss during movement of the liquid-gas mixture in the wellbore and flow lines as compared to the movement of gas only. Well operation is gradually becoming unstable, periodic with the subsequent cessation of natural flowing. The methods of operation of flooded wells are characterized. The use of the gas-lift method for the operation of flooded gas wells in depleted gas fields is justified. The effect of tubing diameter, wellhead pressure and water factor on the parameters of gas-lift operation of flooded wells is investigated. The research is carried out using the improved technique proposed by the authors and the PipeSim program for hypothetical (simulated) well conditions. The studies performed are presented in the form of graphical dependences of the production rate of reservoir gas, the minimum required gas production rate for the liquid to be taken from the bottom of the well to the surface, lift gas flow rate and bottomhole pressure on wellhead pressure, diameter of tubing and water factor. The research results indicate a significant coincidence of the values of the calculated parameters of the gas-lift operation of the watered well according to the proposed methods and the PipeSim program. Using the research results, it is possible to select the optimal diameter of the tubing string and evaluate the value of formation gas flow rate and gas-lift flow rates for various values of water factor and wellhead pressure.
Books on the topic "Tubing movement"
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Page, Phil, and Todd Ellenbecker. Strength Band Training. 3rd ed. Human Kinetics, 2020. http://dx.doi.org/10.5040/9781718225565.
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The top resource on strength band training is now expanded, updated, and better than ever! Whether you are training in the gym, at home, or on the road, Strength Band Training will show you how to maximize strength, speed, and flexibility. Featuring more than 160 exercises and 27 fitness and sport-specific workouts, you will discover why strength bands are the ultimate tool for targeting, isolating, rehabilitating, and developing every major muscle group. In this third edition, you will find a strength assessment index to measure your progress, new chapters on training for older adults and rehabilitation, training tips connecting research to specific exercises, and injury prevention recommendations. Full-color photo sequences accompany the detailed descriptions of each exercise, ensuring safe and proper execution. The exercises allow you to add resistance in multiple directions for routines that simulate sport-specific demands, improve strength, enhance movement, or target muscles to help prevent or recover from common injuries. Whether you are using flat bands or tubing, seeking performance gains or muscle mass, Strength Band Training provides authoritative advice, the most effective exercises, and proven workouts to achieve your goals.
Book chapters on the topic "Tubing movement"
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Yohana, Eflita, Indra Sakti Rahyang, Daffa Shaquille, Putro Adi Nugroho, Mohamad Endy Yulianto, and M. Farkhan H. Dwinanda. "Case Study of Tubing Movement Analysis in Completion Tools Design in Well-X." In Lecture Notes in Mechanical Engineering. Springer Nature Singapore, 2024. http://dx.doi.org/10.1007/978-981-97-0106-3_98.
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Thomson, C. Claire. "“It All Comes from Beer”: Tuborg, Carlsberg, and the Role of Film in Danish Cultural Diplomacy." In Nordic Media Histories of Propaganda and Persuasion. Springer International Publishing, 2022. http://dx.doi.org/10.1007/978-3-031-05171-5_3.
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AbstractIt All Comes from Beer is the title of a 1952 short film, commissioned by Carlsberg to showcase its philanthropic contributions to science and art in Denmark to anglophone viewers. But Carlsberg and its rival brewery, Tuborg, used film at least a quarter-century earlier as “propaganda”, not just for their beer but also for the culture, industry, and landscape of their home country. The case studies in this chapter show how inter-war film genres such as tourist films, promotional footage, educational films, and even science films tended to overlap and merge, depending on where they travelled and to which audiences they were screened. The movement of films and of the material culture (from beer glasses to science equipment) that accompanied them facilitated an entrepreneurial form of cultural diplomacy on Denmark’s behalf.
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Magee, Patrick, and Mark Tooley. "Gas pressure, Volume and Flow Measurement." In The Physics, Clinical Measurement and Equipment of Anaesthetic Practice for the FRCA. Oxford University Press, 2011. http://dx.doi.org/10.1093/oso/9780199595150.003.0018.
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The physics of pressure, flow and the gas laws have been discussed in Chapter 7 in relation to the behaviour of gas and vapour. This section will focus on the physical principles of the measurement of gas pressure, volume and flow. Unlike a liquid, a gas is compressible and the relationship between pressure, volume and flow depends on the resistance to gas flow (or impedance if there is a frequency dependence between pressure and flow in alternating flow, see Chapter 4 for the electrical analogy of this) in conduits (bronchi, anaesthetic tubing); it also depends on the compliance of structures being filled and emptied (alveoli, reservoir bags, tubing or bellows). Normal breathing occurs by muscular expansion of the thorax, thus lowering the intrathoracic pressure, allowing air or anaesthetic gas to flow towards the alveoli down a pressure gradient from atmospheric pressure. When positive pressure ventilation occurs, gas is ‘pushed’ under pressure into the alveoli. Depending on the exact relationship between the ventilator and the lungs, different relationships exist between airway pressure (rather than alveolar pressure, which cannot easily be measured) and gas flow and volume. Gas pressure measurement devices were traditionally in the form of an aneroid barometer, a hollow metal bellows calibrated for pressure and temperature, which contracts when the external pressure on it increases, and expands when it decreases. The movement is linked to a pointer and indicator dial. It is often more convenient to make the device in the shape of part of a circular section, but the principle is the same. This is what the Bourdon gauge, which commonly measures pressure in gas cylinders, looks like. The detection of movement of the diaphragm of an aneroid barometer can take several forms. The movement can either be linked via a direct mechanical linkage to a pointer, or diaphragm movement can be linked to a capacitative or inductive element in an electrical circuit, such as a Wheatstone bridge. Airway pressure during spontaneous breathing or artificial ventilation is low. The preferred units of measurement are cm H2O and the range of values is between −20 and +20 cmH2O. The aneroid barometer to measure this will therefore be of light construction, using thin copper for the bellows material.
Conference papers on the topic "Tubing movement"
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Hannegan, Don M. "Underbalanced Operations Continue Offshore Movement." In SPE/ICoTA Coiled Tubing Roundtable. Society of Petroleum Engineers, 2001. http://dx.doi.org/10.2118/68491-ms.
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Miller, H. J., and A. D. Richard. "Jointed Tubing Injector Snubbing on Extended Reach Wells." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/206223-ms.
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Abstract OBJECTIVE / SCOPE An injector has been developed that is able to continuously move conventional jointed tubing in and out of wells that may be underbalanced. It is an advantage to use the jointed tubing injector rather than coiled tubing or conventional hydraulic snubbing due to cost, speed of operation, transportation, effectiveness, and safety. The paper will describe the function and application of the jointed pipe injector. METHODS, PROCEDURES, PROCESS An injector has been designed with retractable gripping segments integral to the gripper blocks that are able to function on conventional jointed tubing, over interconnecting couplings and with the advantages of continuously operating injector movement. The description is to include how the geometry of the retractable gripper block system works and how the technical and safety risks of a conventional snubbing system or coiled tubing are overcome. Configurations whereby the jointed tubing injector can be used to provide methods of completing wells that are safer and more efficient than coiled tubing or a conventional hydraulic snubbing jack will be presented. RESULTS, OBSERVATIONS, CONCLUSIONS The biggest limitation of coiled tubing is due to its size and residual bend, it is not capable of reaching the end of the well before the wellbore friction causes helical buckling. The OD of the coiled tubing is limited by the available reel sizes and the difficulty transporting the large reels due to road dimensional and weight limitations. Coiled tubing is not able to be rotated at any time in the well. The use of jointed tubing eliminates those limitations. When a well is being completed with a conventional hydraulic snubbing jack, the length of the stroke that the jack can take is limited by the allowable unsupported length of the tubing to ensure that it will not buckle. It is also forced to stop workstring movement each time the jack is reset therefore the static friction of the workstring must be overcome during each movement of the jacks. The design of the jointed tubing injector minimizes the unsupported length of the tubing and allows the continuous movement of the tubing. The operation is less labor intensive, and the controls can be moved to a position that is less exposed to danger. NOVEL / ADDITIVE INFORMATION The Jointed Tubing Injector can continuously move jointed tubulars in and out of a well. There is no other piece of equipment that will address as many of the problems that have been experienced in the completion of extended reach wells. The paper will describe the injector and control system and how it can be applied to solve the challenges.
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Boisvert, Ian, Marshal Allen Strobel, and Michael Szatny. "A Novel Tubing Movement Workflow Increases Efficiency and Planning for Deepwater FracPack Operations." In SPE Deepwater Drilling and Completions Conference. Society of Petroleum Engineers, 2012. http://dx.doi.org/10.2118/155867-ms.
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Yang, Mengshi, Wei Xie, Xuefeng Jin, et al. "The Precise Description of Pumping Rod string and Tubing Movement and Computer Implementation." In 4th International Conference on Renewable Energy and Environmental Technology (ICREET 2016). Atlantis Press, 2017. http://dx.doi.org/10.2991/icreet-16.2017.42.
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Ighalo, Samuel, Keith Romaine, and Blake Andriessen. "Predicting Tubing Movement and Stress on Tubulars During Scale Remediation Jobs Using Computer Simulations." In SPE Nigeria Annual International Conference and Exhibition. Society of Petroleum Engineers, 2016. http://dx.doi.org/10.2118/184355-ms.
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Saponja, J., R. Hari, J. Brignac, D. Jaszan, C. Coyes, and F. Chaudhry. "A Tubing Anchor Engineered for Rod Pumping Horizontal Wells Improves Production Performance." In SPE Artificial Lift Conference and Exhibition - Americas. SPE, 2024. http://dx.doi.org/10.2118/219523-ms.
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High gas to oil ratio (GOR) producing horizontal wells is now commonplace. This ratio continues to rapidly escalate as reservoirs suffer regional and basin wide pressure depletion. The North Dakota Bakkeni formation is a prime example of a concerning GOR trend and can be seen in Figure 1. Higher GOR's and depleted reservoir pressures lead to increased gas rates and multiphase fluid velocities within horizontal wellbores. Increased multiphase fluid velocities can then transport more damaging solids to a sucker rod pump and increase failure frequencies. Consequently, challenges for controlling failure frequencies and workover costs with sucker rod pumping continues to intensify, especially for improving downhole gas and solids separation. Sucker rod pumping normally requires the tubing string to be secured or anchored to the casing, downhole near the sucker rod pump. Anchoring of tubing prevents tubing movement during a rod pump's operating cycle. Tubing movement can undesirably reduce downhole pumping efficiency and increase risks for damage to the tubing, casing, pump and sucker rods. A downhole tubing anchor (TA) or a downhole tubing anchor catcher (TAC) are a bottomhole assembly component installed for this purpose, but they can present risks for increasing operating expenses and limiting of a well's production potential. Production can be limited if the annular flow path cross-sectional area of a tubing anchor (to the casing's internal diameter) is a flow path restriction. A flow path restriction negatively impacts downhole gas separation performance by causing multiphase flow instabilities. Further, sluggy and inconsistent multiphase flows that commonly emanate from a horizontal wellbore can worsen from a flow restriction, making downhole gas separation even more challenging. Flow restrictions can increase turbulence and then cause undesirable foaming and gas entrainment. Foaming of fluids is generally characterized by smaller gas bubbles in the liquid, which are more difficult to separate from the liquid.
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Bakenne, Sulaiman, Stephen Oboh, Ihejirika Vivian, Iheanyi Ugwa, and Okenna Afamefuna. "Viable Options for Managing Thermally Induced Wellhead Movement." In SPE Nigeria Annual International Conference and Exhibition. SPE, 2024. http://dx.doi.org/10.2118/221695-ms.
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Abstract Surface wellhead upward movements may be observed if high temperature fluid stream flows through a well tubing conduit resulting into thermal expansion in the unsupported tubular sections. This is often associated with flowing of high temperature gas injection, high rate high temperature producer or steam injection wells. Initial well design must anticipate these thermal loads and safely manage this movement to prevent damage to well or topside components through optimum pipe specifications, adequate cementing job design and topside flowline movement tolerance to allow predefined magnitude of wellhead movement. Over the well lifecycle, fatigue and degradation could result in increase in unsupported well sections resulting in an amplified thermal load impact. Therefore, periodic surveillance is critical to ensuring thermal loads remain within the safe operating envelope. This paper focuses on non-rig based options to managing wellhead movement to ensure safe well operations on a case study gas injector well A. Options evaluated include lock restraint design/installation, displacement of production annulus to insulating packer fluid and lastly defining a safe movement window. For this case study well A, multistring wellhead movement modelling was done using WELLCATTM. Result of analysis showed that a lock restraint option resulted in significant pipe compression and buckling potentially outside the design envelope. Thermal insulating fluids reduced thermal loads though marginal in this case study due to limited annular clearance. Last option considered was constraining injection temperature to ensure a safe wellhead movement margin that keeps pipe loads within design envelope. Implementing a systematic workflow to manage wellhead movement will enable operators adopt a balanced and fit-for-purpose strategy to minimize safety risk and maximize well service life.
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Nurmohamed, D., H. Chin Lien, and S. Kisoensingh. "Case Study for Reducing Tubing Failures in Suriname's Tambaredjo Field." In SPE Energy Resources Conference. SPE, 2014. http://dx.doi.org/10.2118/spe-169978-ms.
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Abstract In Staatsolie, as of December 2013, there were 1549 shallow wells from its 3 oilfields. One thousand one hundred and thirty (1130) of these were in the Tambaredjo field (TAM field). In the 3 decades of its operations, the prime mechanism for lifting the 15.6oAPI crude to surface has been with progressive cavity pumps (PCP). The down hole pumps are surface driven and installed at an average true vertical depth (TVD) of 1000 ft. Oilfield best practices are employed in the design, installation and operation of the production strings and pumps. In the period 2008-2012 an average 580 down hole failures occurred annually of which 54% was caused by tubing leaks, with a repetitive frequency of up to 6 faillures per year on individual wells. Visual inspection of internal tubing's have shown that the principal failure mechanism stems from rod tubing wear (abrasion caused by the rotational motion) exacerbated by the corrosiveness of the produced fluids. Most of the tubing wear occurs at the tubing body in direct contact with the rod couplings. It is found that most tubing leakages (up to 70%) occur on the lower part of the tubing string above the pump. Previous installation of shorter rods above the pump, which is causing a high eccentrically movement of the rod string, also increased the occurrences of these failures directly above the pump. In an effort to reduce these tubing failures, an eight-well pilot program was commenced to install rod guides in wells with the highest failure rate and to install a sucker rod of 25 feet right above the pump. These eight wells were selected based on their high tubing failure rates. Although the program is still being conducted, preliminary results thus far have been quite promising in these wells. In four (4) wells, the work-over frequency was reduced from average 5 to 3 jobs per annum resulting in 40% reduction. The remaining 4 wells are still producing after an average 5-month period without any tubing failures. This paper presents the approach and strategy used to minimize rod-tubing wear in shallow vertical well applications based on the outcome of the pilot test.
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Kalwar, Ghulam Murtaza, Saad Hamid, Sharat Kishore, Abdulrahman A. Aljughayman, Nahr M. Abulhamayel, and Nasser F. Qahtani. "E-Line Powered Mechanical Tool Technologies Provide Efficient, Reduced Risk Solutions in Complex Intervention Operations." In International Petroleum Technology Conference. IPTC, 2021. http://dx.doi.org/10.2523/iptc-21393-ms.
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Abstract Latest developments in drilling and wellbore completion technologies lead to even more complex intervention conditions. Conventional techniques using slickline or coiled tubing are ill-suited for many of these conditions due to operational complexity, effectiveness, or efficiency. Powered mechanical intervention with e-line alleviates some of these limitations and opens lower risk intervention applications. This paper details two applications: a fishing operation that could not be performed with slickline or coiled tubing and a completion disk rupturing operation where the operator saved 1.5 days. Powered mechanical intervention is a combination of complementary technologies that enable "intelligently controlled intervention operations." Downhole tractors enable access into complex well trajectories. Surface-controlled, powered anchors coupled with a linear actuator can generate very high axial forces with precise and real-time downhole measurements of forces and displacement. Operating parameters can be monitored in real time to prevent damage to damaged completion components. Uncontrolled tool movement due to high differential pressures is prevented. Such precise control of downhole forces and movements enables complex intervention operations previously done with coiled tubing or a full workover. The first application example details a fishing operation. A retrievable plug along with its setting tool was stuck in the production tubing after prematurely setting. Multiple fishing attempts with heavy-duty slickline jars were unsuccessful. Coiled tubing was not deployed as its lack of force precision could have generated excessive downhole force and sheared the fish. An e-line-conveyed linear actuator tool was used to latch onto the fish with the help of an overshot and was released from the retrievable plugs by application of optimal, highly controlled, linear force to minimize damage. The second case involved rupturing a ceramic disk installed in completion. High differential pressure across the disk restricted the use of slickline which could have been damaged due to the high expected differential pressure. The alternative with coiled tubing milling requires a larger personnel and equipment footprint in addition to the associated HSE exposure and lack of efficiency. An innovative technique using the e-line linear actuator and a pointed chisel was devised and deployed. Real-time feedback from the tool sensors gave confirmation of the rupturing of various components of the ceramic disk, and the anchors eliminated any tool movement during pressure equalization. The operation was completed in 12 hours, resulting in time savings of almost 36 hours. An e-line intervention is a low risk, effective, and efficient solution while having an accurate depth and positioning, coupled with controlled downhole operations. With precise control of operating parameters, operations which were previously possible with coiled tubing or workover can be done on e-line more efficiently.
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Huseynov, Tural, Godwin Jackson Effiong, and Zinner Christoph. "Optimization of Maintenance and Storage Strategy of CT Unit Based on Field LLs." In ADIPEC. SPE, 2024. http://dx.doi.org/10.2118/222098-ms.
Full textAbstract:
There are a lot of field learnings that can potentially minimize the existing gaps in oil & gas industry standards and enhance safety levels of this hazardous environment. This paper will describe two different incidents in coiled tubing (CT) operations in BP Oman that led to optimization of maintenance for injector head and change in strategy of coiled tubing string storage. Both incidents were considered high-risk events, where one was an uncontrolled and sudden movement of coil into hole, and another one was a pin hole in coil during pumping.