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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.
The first 3D burst capacity models are developed herein. The development of the 3D burst capacity models is a major advance from the past 50 years, during which numerous 2D bursting failure prediction models (so-called burst capacity models) were developed. These 2D models have become more complicated and less practical while trying to reduce their relatively low accuracy and poor stability in their burst pressure predictions. The 3D models bring simplicity and accuracy together by employing a new parameter, the volume of the defect, to estimate, accurately, the burst pressure of steel pipelines with localized defects of complex morphology. For development and validation of these new models two sets of numerical simulations and a series of innovative full-scale burst capacity tests were carried out.
Pipelines are an important component of critical infrastructure and are the most energy-efficient, least environmentally disruptive, and safest technology for high-capacity transportation of hydrocarbon and other similar products [Mokhtari and Nia, 2015]. For instance, in 2009, 97% of Canada’s oil and natural gas was transported through nearly 580,000 km of pipelines [Bedairi, Cronin, Hosseini and Plumtree, 2012].
Corrosion is one of the main reasons for failures of onshore and offshore pipelines [Cosham, Hopkins and Macdonald, 2007]. $2.2 trillion is the approximate global annual cost of corrosion on the world economy of which about 45% is associated with the cost of corrosion in oil, gas and petrochemical industries [“Raising Awarenes,” 2018].
The US Department of Transport (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) reports reveal that in the USA alone during the period 1998-2017, apart from the large loss of product and catastrophic damage to facilities and environment that cost over $8.1 billion, there were 306 fatalities and 1259 injuries resulting from 5716 incidents related to oil, gas and hazardous fluid pipeline failures [“Pipeline Significant Incident,” 2018].
Over the past four decades, numerous fracture prediction models for corroded pipelines, so-called burst capacity models have been developed. These models predict the burst pressure of corroded pipelines with localized corrosion defects [Cosham, Hopkins and Macdonald, 2007]. Studies by Kiefner et al.  can be considered as the first work done in this field. Their research led to the well-known ASME B31G criterion  that is a simple model to use. ASME B31G was found to be too conservative and thus it was modified to ASME Modified B31G [Kiefner and Vieth, 1989]. These models have been usually referred to as “easy-to-use” since they have used simplistic 2D geometries such as rectangular and parabolic to represent the longitudinal corrosion area of the pit. These simplistic pit geometries are shown in [Adib-Ramezani, Jeong and Pluvinage, 2006]. There are other “easy-to-use” and well-known burst capacity models such as SHELL92 [Ritchie and Last, 1995], PCORRC [Leis and Stephens, 1997, Stephens and Leis, 1997, Stephens, Leis and Kurre, 2000], and the DNV-RP-F101 model for single defects . To calculate the burst pressure with these “easy-to-use” models only the length and maximum depth of the corrosion defect (in addition to pipe size and material properties) are required. Of course, the pit geometry simplification has some consequences including large scatter in burst pressure predictions and/or excessively conservative predictions in some cases [Mokhtari and Melchers, 2016, Mokhtari and Melchers, 2018, Motta, Cabral, Afonso, Willmersdorf, Bouchonneau, Lyra and de Andrade, 2017, Teixeira, Guedes Soares, Netto and Estefen, 2008, Zhou and Huang, 2012]. The large scatter alone diminishes the reliability of such simple models.
Sulfide stress cracking has special importance in the Oil and Gas (O&G) industry due to the considerable amount of hydrogen sulfide that may be present in the processed fluids. Furthermore, the increasing interest of the O&G industry on high grade tubulars to work at high pressure, makes the sulfide stress cracking phenomenon an important issue in the safe operational condition assessment of Oil Country Tubular Goods (OCTG).
Consequently, the adequate determination of fracture toughness value (i.e.: K-mat) is of fundamental importance for fitness for purpose evaluation. Particularly, the fracture toughness of OCTG materials in aggressive media is usually determined using Double Cantilever Beam (DCB) specimens and the obtained Klimit values are the employed for fracture assessment. Although, Method D using DCB specimens have been and are the currently recognized testing methodology for pipe manufacturing QA/QC, its validity as a test to obtain the fracture resistance parameter for burst pressure estimation of flawed pipes remains uncertain and therefore alternative methods are being assessed.
In the present paper, an experimental program is described. API 5CT-C110 grades were tested in aggressive environments. Klimit from conventional DCB tests and Kthreshold from Single Edge Notch Tension (SENT) specimens under constant loading are compared and discussed. The Kmat obtained from both testing techniques are used to calculate the burst pressure of flawed pipes using API 579(1) equations. The presented results and discussion allow incorporation of further insights on an alternative testing method and specimen geometry for brittle burst assessment of flawed pipes in an aggressive media.
It is widely known that the presence of hydrogen in metal alloys strongly affects their mechanical and fracture mechanics properties. As a result, pipes made of carbon steel may have deteriorated performance when operating in sour environments. The sulfide stress cracking susceptibility of steels used for oil and gas applications has been extensively studied and some test are standardized.
NACE(1)1 Standard Test Methods for testing of metals for resistance to sulfide stress cracking in H2S environments (TM0177)1 describes four tests methods, in which pre-loaded specimens are exposed to acidified brine saturated with H2S. In particular, Method D uses a Double Cantilever Beam (DCB) specimen.
Most composite repair installations take place with some amount of pressure in the pipe. The traditional design standards, ASME PCC-2 Article 4.1 and ISO 24817, each provide a design equation that includes consideration of installation pressure but the equations up to this point have been theoretical only and never tested. It is important to note that in the equations, an increasing installation pressure acts to reduce the required composite repair thickness. This experimental test program studied the effects of internal pipe pressure during installation on composite reinforcement systems to verify if the performance of the repair was maintained when applied to simulated corrosion defects. The full-scale testing analyzed the effects on the burst pressure and the cyclic pressure fatigue life of a pipe with a simulated 50% wall loss corrosion defect. The installation pressures considered were varied from 0 up to 50% yield pressure. The installation pressure had no noticeable effects on the burst pressure or the cyclic pressure fatigue life of the pipe; however, the defect region always remained in elastic region during installation. These results indicate that future design work should conservatively assume the installation pressure is 0.
Composite repairs are increasingly being used to repair defects within pipelines suffering from a wide range of degradation issues. With their ease of installation, low cost and rapid delivery to site, they are becoming a go-to method for repairing common defects. In addition, composite systems impregnated with the polymer onsite can conform to most any shape found negating fitment and tolerance issues commonly associated with machined and forged type repairs. The most common composite repair systems are composed of a fabric, such as fiberglass, carbon, Kevlar or a combination, suspended in an epoxy or urethane polymer.
Early field deployment of the repair systems experienced a range of performance, both good and bad, due to the lack of agreed upon design and quality control documentation. Anyone was able to supply off the shelf fabrics and polymers and apply them to damage zones, but they often lacked a technical supporting basis. Some composite systems were subjected to coupon level or full-scale testing that defined their performance envelope; however, other systems were not which left the pipeline operators and the public exposed to risks ranging from minor leaks to complete failure.
To study the effect of interaction between colonies of defects on the burst pressure of corroded pipeline, ten experimental cases were designed. Among them, the specimens containing two longitudinal or circumferential aligned defects with different sizes and spacings were fabricated. Burst tests were conducted on the ten tubular specimens. Burst pressures and strains on the surface of defects were measured. The effects of defect sizes and spacings on burst pressures and strains of corroded pipeline were analyzed. Meanwhile, based on the experimental results, the performance of the five interaction rules such as DNV RP F101, API 579, BS 7910, Kiefner and Vieth, Pipeline operator forum (POF) on failure pressure are evaluated.
Due to the harsh environment and the role of aggressive medium, failures of oil/gas transmission pipelines with corrosion defects become of major concern in pipeline integrity management. Wall thinning caused by corrosion on the internal or external surface of the pipelines will result in stress concentration in the pipe wall. Consequently, appropriate residual strength evaluation of corroded pipelines is vitally important. A significant effort over the past 40 years has been made to study the behavior of metal-loss defects of corroded pipeline under static internal pressure using experimental methods.
The failure behavior of a colony of closely spaced defects is much more complex than the failure behavior of an isolated defect. The interaction between adjacent defects has a significant influence on the failure mode and capacity of corroded pipeline with colonies of defects. Burst tests for specimens containing machined irregular or complex-shaped external defects (Freire, Vieira, Castro and Benjamin, 2007) were conducted. Laboratory tests (Benjamin, Freire and Vieira, 2007) were performed with 12 tubular specimens containing groups of interacting defects comprising the combination of two or more base defects. However, for the above tests, the defects comprising the colonies of corrosion had the same size such as length, width and depth. The effect of interaction between colonies of corrosion with different sizes on burst pressure was seldom studied.
Metallic strips flexible pipe has been favored in the offshore pipelines engineering for its good corrosion resistance, high strength, easy installation etc. This new composite pipe can be regarded as promising alternative for submarine pipelines. In this paper, the cross-sectional design process for this specific kind of pipe is illustrated. Three formulas for calculating the individual strength capacities of the pipe when subjected to internal pressure, external pressure and pure bending are presented for initial screening assessment. And then a case study for an 8 inch metallic strip flexible pipe based on a shallow water application is carried out. Several FE models are established by using commercial software ABAQUS to verify the designed cross section. The two methods presented could be used to assess the structural performance of the pipe in the early design phase, which might be interesting to the manufacture engineers.
Composite pipes are extensively used in the offshore oil/gas industries for decades. Typical composite pipe, take reinforced thermoplastic pipe (RTP) as example, is favored in engineering for its good corrosion resistance, high strength, high flow rates and etc. Recently, metallic strips flexible pipe is emerging in the offshore application. It has the same advantages as RTP. Furthermore, it exhibits better on-bottom stability due to its relatively greater weight and the production costs are quite low. Fig.1 shows the typical configuration of metallic strips flexible pipe. Generally, it can be divided into three components: (1) an inner extruded thermoplastic tube that seals the transported products. (2) metallic strips reinforced layers with winding structure that provide the strength against internal pressure and tension. (3) an outer PE sheath that isolates the underlying layers of the pipe from external environments. The winding angle and the geometry of the metallic strips can be selected based on the design pressure and the corresponding functional requirements. During the metallic strips flexible pipe's installation and service periods, it will inevitably carry operational and environmental loads such as external pressure, internal pressure, bending, tension, torsion and etc. The requirements of these capacities of metallic strips flexible pipe have a significant impact on the cross-sectional design. The derivations of the individual capacities for the metallic strips flexible pipe are illustrated step by step in this paper, which may be of interest to manufacturer engineers.
ABSTRACTThe specific repair design of nonmetallic composite systems is a critical component to the successful usage of this relatively new and advanced material group when applied as a repair of pipeline defects. Various design methodologies are currently available within the existing composite repair design documents, ASME PCC-2 Article 4.1 and the ISO/TS 24817, based on the level of testing and understanding of the specific composite system being used1,2. The purpose of this paper is to discuss a testing program to validate the effectiveness of a composite repair system when designed according to formulas using a strain based approach rather than a stress based approach. Simulated corrosion defects manufactured into steel pipe test spools were severe in nature, including high percentage wall losses with large dimensions and also large wall losses into the weld seams of the pipe specimens representing a very severely damaged pipeline. Pressure cycling and ultimate failure pressure testing was conducted on various pipe samples to verify the design formulas meet the specifications and are correct for use in design of field repairs. The results of this testing show that the use of strain-based design methodologies for composite repair systems is suitable and effective for long term repairs being applied to pipelines.INTRODUCTIONComposite repair systems on pipe substrates have been used successfully for leak sealing and for reinforcement of pipework in low pressure applications often found in the process industries. Their use has also expanded into pipeline integrity to address corrosion and mechanical damage, similar to the concept of welded steel sleeves. “Selection of Pipe Repair Methods”, a research project recently published in June 2013, solely based on the composite repairs which was prepared by Gas Technology Institute (GTI) and sponsored by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (DOT PHMSA) Office of Pipeline Safety and provides a comprehensive analysis of composite repairs3 The report also evaluates the performance of metallic and composite repair methods. The purpose of the report was to establish procedures and perform long-term tests to evaluate the performance of composite repair methods and reduce the risks of ineffective or faulty repairs. The report states the most significant parameters which affect the performance of the repair are the pipe size, applied pressure and tensile modulus of the composite repair system.
The pursuit of hydrocarbon reserves and increased oil production means that operators continue to look to prolific high-permeability, clastic reservoirs that can be found in basins around the world.
The use of high-deviation and horizontal well trajectories in these fields increases the amount of reservoir contacted by the wellbore, which improves productivity but increases the challenges of sand control.
Practical sand-control options for these wells include gravel packs, standalone screens, and slotted liners. The lower flux rates in extended-reach wells, and the high cost of gravel packing mean that operators are increasingly turning to standalone screens as the solution. However, the choice of screen will depend on the particular application to ensure that the well completion can retain the sand, avoid plugging and erosion, and maintain mechanical integrity.
Subsea deployments, exits through milled windows, and long horizontal wells with swelling shales or unstable boreholes require a more robust and mechanically stronger solution. Other, less challenging wells may not require this level of mechanical performance yet still may need a sturdier sand-control solution than the use of standard screens.
Weighing costs and benefits has become increasingly important in the current economically challenging environment. Operators cannot afford to use over-engineered solutions and demand a more focused option to fit their needs. Specifically, there is an increasing need for screens that are engineered to reduce cost and maintain performance but are stronger than a traditional screen.
An effective sand screen is designed to allow the larger formation particles to bridge across the openings to offer maximum fluid flow area and reduce plugging. Smaller formation particles are then retained behind the larger “bridged” particles. Premium screens incorporate layers of metal mesh or weave to handle a larger range of particle sizes while increasing the fluid flow area and providing greater mechanical strength and erosion resistance.
Herein a new study is described to evaluate the accuracy of the wellknown burst capacity models and recent FEM studies which employed idealized pit shapes. For this purpose, several severe pits with different aspect ratios and natural complex shapes are modeled on the exterior surface of carbon steel pipes. The finite element models used in the present study are verified against experimental data. Results from present study show that complex pit shapes can be modeled numerically as idealized semi-elliptical shapes with a very good approximation. In addition, in most cases, the DNV model and PCORRC had the most accurate predictions on the burst pressure of the studied corroded pipes.
Pipelines are amongst the most important elements of lifelines and are the safest and the least environmentally disruptive means for high capacity transmission of water, gas, oil, etc. Recently, failures of carbon steel pipelines caused by corrosion and in particular as a result of severe pitting corrosion have become of major concern in maintaining pipeline integrity, particularly where cathodic protection is not provided and where protective coating systems have become dysfunctional. To aid maintenance of pipeline reliability, a number of burst capacity models have been developed for the assessment of remaining strength of corroded pipelines. Modified B31G (Kiefner and Vieth, 1989), the CSA model (2007), the DNV model (2004), PCORRC (Stephens and Leis, 1997; Leis and Stephens, 1997; Stephens and Leis, 2000), RSTRENG (Vieth and Kiefner, 1993) and SHELL92 (Ritchie and Last, 1995) are well-known burst capacity models whose accuracy is investigated in the present study. ASME B31G (1984) is not considered in the current study as it is already modified to Modified B31G due to its excessive conservations. The equations of abovementioned burst capacity models are as follows:
ABSTRACT For the past decade, offshore oil and gas observed more challenging realms of the industry which include ultradeep waters, harsher environments, and higher pressures and temperatures. The most notable of such is the challenges of high pressure high temperature (HPHT) conditions which are still regarded as uncharted territories and have prompted the industry to deliver safe and reliable solutions. For riser systems, HPHT conditions can require higher than usual pipe wall thickness, which can lead to pipe manufacturing and fabrication issues as well as riser payload and hang-off system challenges to the floating facility. Conventional design codes will be reviewed for riser sizing, hence suitable assumptions will be derived for riser sizing methodologies in HPHT applications. The purpose of this paper is to discuss the conventional thin-wall and thick-wall riser wall sizing designs and provide recommendations the appropriate sizing of the riser in HPHT applications. INTRODUCTION Over the past decade, high pressure high temperature (HPHT) hydrocarbon bearing wells have been recognized as the new frontier in offshore oil and gas recovery. Coupled with ultra-deep waters and harsh environments, delivering safe and reliable pressure containment systems in HPHT conditions, along with the steadfast risks of offshore hydrocarbon drilling and production, have become the next set of challenges the industry must overcome.