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The most important mechanical properties of casing and tubing are burst strength, collapse resistance and tensile strength. These properties are necessary to determine the strength of the pipe and to design a casing string. If casing is subjected to internal pressure higher than external, it is said that casing is exposed to burst pressure loading. Burst pressure loading conditions occur during well control operations, casing pressure integrity tests, pumping operations, and production operations. The MIYP of the pipe body is determined by the internal yield pressure formula found in API Bull. This equation, commonly known as the Barlow equation, calculates the internal pressure at which the tangential (or hoop) stress at the inner wall of the pipe reaches the yield strength (YS) of the material.
Over the years, attempts have been made to track the working history of coiled tubing (CT) strings in service to maximize the service utility of the tube while minimizing fatigue failures. As a result, three commonly used methodologies for predicting the fatigue condition of the CT were developed. A relatively simplistic approach used to predict the working life of coil tubing is commonly described as the "running-feet" method, in which the footage of tubing deployed into a wellbore is recorded for each job performed. This deployed footage is then added to the existing record of footage deployed in service for any given string. Depending upon the service environment, type of commonly performed services, and local field history, the CT string is retired when the total number of running feet reaches a predetermined amount.
Abstract Coiled tubing (CT) integrity is critical for well intervention operations in the field. To monitor and manage tubing integrity, the industry has developed a number of computer models over the past decades. Among them, low-cycle fatigue (LCF) modeling plays a paramount role in safeguarding tubing integrity. LCF modeling of CT strings dates back to the 1980s. Recently, novel algorithms have contributed to developments in physics-based modeling of tubing fatigue and plasticity. As CT trips into and out of the well, it goes through bending-straightening cycles under high differential pressure. Such tough conditions lead to low- or ultralow-cycle fatigue, limiting CT useful life. The model proposed in this study is derived from a previous one and based on rigorously derived material parameters to compute the evolution of state variables from a wide range of loading conditions. Through newly formulated plasticity and strain parameters, a physics-based damage model predicts CT fatigue life, along with diametral growth and wall thinning. The revised modeling approach gives results for CT damage accumulation, diametral growth, and wall thinning under realistic field conditions, with experimental validation. For 20 different coiled tubing alloys, it was observed that the model improved in accuracy overall by about 18.8% and consistency by 14.0%, for constant pressure data sets of more than 4,500 data points. The modeling results provide insights into the nonlinear nature of fatigue damage accumulation. This study allowed developing recommendations to guide future analytical modeling and experimental investigations, to summarize theoretical findings in physics-based LCF modeling, and to provide practical guidelines for CT string management in the field. The study provides a fundamental understanding of CT LCF and introduces novel algorithms in plasticity and damage.
Abstract This paper proposes a new analytical derivation to incorporate bending and torsion into collapse calculation, further pushing the already existing approach of combined loading equivalent grade proposed in API TR 5C3 (2019) Clause 8.4.6 Eq. (42) for axial stress and internal pressure (identical to ISO TR 10400 Clause 8.4.7) used to calculate a differential collapse pressure. This new derivation is also based on Hencky-von Mises maximum distortion criterion. The interest of developing such combined loading equivalent grade is to enable the use of the four collapse types described in Clause 8 i.e., Yield Strength, Plastic, Transition and Elastic. The formulae are adapted to a closed-form equation similar to current Eq. (42), enabling pipe collapse performance calculation. Newly derived formulae are checked against a size governed by yield strength collapse to verify consistency. The restrictions regarding collapse performance under compression are discussed.
The majority of mechanical equipment found in oil and gas facilities belongs to the static equipment group, which comprises pressure vessels (drums, columns, reactors, filters) and heat exchangers (shell and tubes, plate and frame, air coolers). The presented guidelines contain cost-effective recommendations for their design, materials, and fabrication. They aim to enable the project engineer, who is not an equipment specialist, to check that economical choices are made. The specification and selection of the equipment is the responsibility of the static equipment engineer, based on requirements specified by other disciplines, including process, materials and plant layout. These other disciplines are not always aware of the impact of their demands on the cost/lead time of the equipment. Conversely, the static equipment discipline is not always aware of where the requirements of these disciplines come from and if the onerous ones could be challenged. Such interface data are the focus of this article, which aims to give a cross-discipline awareness. Let's start with the review of the process equipment data sheet. The process engineer defines the design pressure by applying common and reasonable margins above the maximum operating pressure, as shown below. The design temperature is usually set 15-20 C above the maximum continuous operating temperature.
The existing American Petroleum Institute (API) equation for internal leak predicts the internal pressure to overcome the pin-box contact pressure generated from the makeup interference plus the energizing effect of internal pressure, which enhances the seal. For threaded connections, internal and external pressures close the connection and increase the leak resistance, whereas axial loads open the connection and decrease the leak resistance. These competing effects must be included to accurately assess the connection leak resistance under any combination of loads at any point in any string. Following the same approach used by the API for internal leak, this paper obtains similar results for external leak. For API connections, the effects of combined axial force and backup pressure are then incorporated into the internal/external leak equations using results from a “toy connector” elastic model. Sensitivities of leak ratings to combined loads for API connections are presented for both tubing and casing sizes. An example design case shows the importance of considering combined loads.
Recently, well design engineers attempted to replace traditional API 5CT pipes with cheaper UOE steel pipes in the downhole wellbore construction. The UOE method for producing longitudinally welded large-diameter pipes creates typically weaker pipes in terms of collapse resistance. The standard API 5C3 collapse design procedure no longer meets safety requirements. A practical solution to this issue is discussed.
UOE pipe casing can be designed based on the new collapse strength envelope, which is established by modifying the API RP1111 collapse strength model. The original API RP1111 collapse strength model was intended for pipeline design, not downhole tubular design. It is comprised of the elastic collapse term and yield collapse term, with the latter being proportional to material yield strength. However, the deration effects of temperature, tension, and internal pressure are not included. For downhole wellbore tubular design, yield strength is replaced with equivalent yield strength (from API 5C3 new addendum), which is a function of temperature, axial stress, and internal pressure.
A new casing design workflow has been implemented in the computer program, and case studies were performed to verify the collapse design results. A new collapse pressure envelope was generated using the computer program integrated with a commercial tubular design tool and was compared to the traditional API 5C3 collapse pressure envelope. As expected, the new collapse strength values, calculated using the modified API RP1111 collapse model, are typically much lower than the estimated values using the API 5C3 collapse formula.
Results of the collapse safety factor and maximum allowable wear are also compared between the modified API RP1111 collapse model and the traditional API 5C3 collapse model. Typically, UOE pipe using the modified API RP1111 collapse model generates lower safety factor and maximum allowable wear values, as expected.
The API RP1111 collapse strength model has been modified to include the deration effects of downhole conditions. Implementing this model in the commercial tubular design tool enables the cost-effective design of wellbore casing strings using cheaper UOE-manufactured steel pipes.
Seymour, D. A. (Total) | Oyovwevotu, J. (Total) | Vavasseur, D. (Total) | Albores, S. O. E. (Tenaris) | Casares, V. (Tenaris) | Garcia, E. G. (Tenaris) | Innamorati, L. A. (Tenaris) | Izquierdo, G. A. (Tenaris) | Langrill, C. M. (Tenaris) | Mazzina, R. O. (Tenaris) | Mitchell, A. C. (Tenaris) | Santi, N. (Tenaris)
The Culzean field combines both UHPHT reservoir conditions and an unusually narrow drilling window, at the top of the main reservoir, where reservoir pressure lies on a regional ‘broken seal’ rock strength line. This drove a need to find an improved well architecture, to allow production wells to be drilled close enough to the reservoir crest to maximize gas production volumes.
The solution: to develop heavy, ultra-high strength, sour service tubulars and use these in a well layout more typical of Deep Water designs than North Sea HPHT wells. Instead of setting a full production casing string, before drilling the target reservoir, a short production casing liner is hung from the fully rated sour service intermediate string, and tied back after the reservoir section has been drilled and a production liner run. This greatly reduces drilling circulating pressure losses in the reservoir section, allowing crestal targets, whilst providing very robust intermediate and production casing strings for long term well integrity. The reduction in ECD combined with the use of MPD technology, enables the drilling of this complex reservoir, in a safe and efficient manner.
Kuang, Wenyu (National University of Singapore) | Ong, Paul, Pang Awn (National University of Singapore) | Quek, Ser Tong (National University of Singapore) | Kuang, Kevin, Sze Chiang (National University of Singapore)
Pipelines are critical for transportation of oil and gas. A Steel Strip Reinforced Thermoplastic Pipe (SSRTP) is applied in the offshore environment because of its superior mechanical performance. Due to the complex subsea conditions, SSRTP is subject to severe loading and may be damaged during its design life. The failure modes of SSRTP, related to four principle loading cases, are investigated in the FE models. The preliminary results will reveal the mechanical behavior of the critical layer of SSRTP prior to damage. An optical fiber sensor is then introduced within the SSRTP as a novel system to monitor the strain of the critical layer.
Abstract Metal-polymer coiled tubing (MCT) are flexible pipes based on a copolymer reinforced with steel tape, wires and ropes. During the research was proposed and justified eleven constructions of MCT with twenty options of overall dimensions. Next, mathematical modeling of the actual stress conditions of MCT in standard operations during the overhaul of wells was carried out, as well as calculations of the strength of the MCT. The result was the identification of most promising options for the implementation of MCT, as well as the proposed area of their implementation. In addition, have been introduced coefficients for rational selection of most effective MCT structure for a specific well operation from both a technical and economic point of view. The scientific and technical novelty of metal-polymer coiled tubing is confirmed by Patent for an invention, as well as the results of a thorough analysis of patenting of coiled tubing devices. Application of MCT fully meets the challenges of the modern fuel and energy complex of the Russian Federation in the direction of creating modern and safe technologies for offshore fields (including Arctic fields), as well as within the framework of the import substitution policy implemented in our country. Production of proposed metal-polymer coiled tubing can be organized in a full cycle at domestic enterprises, as well as all components of MCT are also produced in our country. This statement was confirmed when creating prototypes of pipes in a volume of 3000 meters. If ongoing laboratory tests of metal-polymer coiled tubing will be finished with positive results, then will be carried out pilot implementation of the proposed pipes in one of the domestic oilfield services companies. The timing of implementation this idea will be minimal, since significant costs are not required for the re-equipment of factory facilities for the manufacture of the proposed MCT. At the same time, final cost of manufacturing MCT on average, according to research results, is on 50 – 100 percent lower than the cost of a GT-70 steel coiled tubing manufactured by Global Tubing USA of similar dimensions. It is worth noting that the MCT, as well as the steel coiled tubing pipe, fully meets all environmental safety requirements, and that is why its use on offshore projects (where environmental friendliness is one of the main requirements for implemented technologies) is considered the most probable. As for increasing labor productivity, initially coiled tubing is an advanced industry with a high technological level. Application of metal-polymer coiled tubing as an alternative to steel coiled tubing in certain well operations will increase the number of hoisting operations for one pipe, which will increase its service life, and will also help to optimize financial costs of relocating equipment.