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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 American Petroleum Institute (API) has numerous manufacturing requirements for tubing. Many API standards have also been adopted by the International Standards Organization (ISO). The tubing purchaser and designer should be aware of API requirements and testing procedures (see API Spec. All tubing should meet API minimum requirements. In critical wells, the purchaser may want to receive and review the manufacturer's test results.
In the context of metal, yield strength is the stress at which a material exhibits a specified deviation from the proportionality of stress to strain. The deviation is expressed in terms of strain by either the offset method (usually at a strain of 0.2%) or the total-extension-under-load method (usually at a strain of 0.5%).
Abstract Drilling challenging wells requires a combination of drilling analytics and comprehensive simulation to prevent poor drilling performance and avoid drilling issues for the upcoming drilling campaign. This work focuses on the capabilities of a drilling simulator that can simulate the directional drilling process with the use of actual field data for the training of students and professionals. This paper presents the results of simulating both rotating and sliding modes and successfully matching the rate of penetration and the trajectory of an S-type well. Monitored drilling data from the well were used to simulate the drilling process. These included weight on bit, revolutions per minute, flow rate, bit type, inclination and drilling fluid properties. The well was an S-type well with maximum inclination of 16 degrees. There were continuous variations from rotating to sliding mode, and the challenge was approached by classifying drilling data into intervals of 20 feet to obtain an appropriate resolution and efficient simulation. The simulator requires formation strength, pore and fracture pressures, and details of well lithology, thus simulating the actual drilling environment. The uniaxial compressive strength of the rock layer is calculated from p–wave velocity data from an offset field. Rock drillability is finally estimated as a function of the rock properties of the drilled layer, bit type and the values of the drilling parameters. It is then converted to rate of penetration and matched to actual data. Changes in the drilling parameters were followed as per the field data. The simulator reproduces the drilling process in real-time and allows the driller to make instantaneous changes to all drilling parameters. The simulator provides the rate of penetration, torque, standpipe pressure, and trajectory as output. This enables the user to have on-the-fly interference with the drilling process and allows him/her to modify any of the important drilling parameters. Thus, the user can determine the effect of such changes on the effectiveness of drilling, which can lead to effective drilling optimization. Certain intervals were investigated independently to give a more detailed analysis of the simulation outcome. Additional drilling data such as hook load and standpipe pressure were analyzed to determine and evaluate the drilling performance of a particular interval and to consider them in the optimization process. The resulting rate of penetration and well trajectory simulation results show an excellent match with field data. The simulation illustrates the continuous change between rotating and sliding mode as well as the accurate synchronous matching of the rate of penetration and trajectory. The results prove that the simulator is an excellent tool for students and professionals to simulate the drilling process prior to actual drilling of the next inclined well.
Abstract Assurance of well integrity is critical and important throughout the entire well's life cycle. Pressure build-up between cemented casings annuli has been a major challenge all around the world. Cement is the main element that provides isolation and protection for the well. The cause for pressure build-up in most cases is a compromise of cement sheath integrity that allows fluids to migrate through micro-channels from the formation all the way to the surface. These problems prompt cementing technologists to explore new cementing solutions, to achieve reliable long-term zonal isolation in these extreme conditions by elevating shear bond strength along-with minimal shrinkage. The resin-cement system can be regarded as a novel technology to assure long term zonal isolation. This paper presents case histories to support the efficiency and reliability of the resin-cement system to avoid casing to casing annulus (CCA) pressure build-up. This paper presents lab testing and application of the resin-cement system, where potential high-pressure influx was expected across a water-bearing formation. The resin-cement system was designed to be placed as a tail slurry to provide a better set of mechanical properties in comparison to a conventional slurry. The combined mixture of resin and cement slurry provided all the necessary properties of the desired product. The slurry was batch-mixed to ensure the homogeneity of resin-cement slurry mixture. The cement treatment was performed as designed and met all zonal isolation objectives. Resin-cement’s increased compressive strength, ductility, and enhanced shear bond strength helped to provide a dependable barrier that would help prevent future sustained casing pressure (SCP). The producing performance of a well depends in great part on a good primary cementing job. The success of achieving zonal isolation, which is the main objective of cementing, is mainly attributed to the cement design. The resin-cement system is evolving as a new solution within the industry, replacing conventional cement in many crucial primary cementing applications. This paper highlights the necessary laboratory testing, field execution procedures, and treatment evaluation methods so that this technology can be a key resource for such operations in the future. The paper describes the process used to design the resin-cement system and how its application was significant to the success of the jobs. By keeping adequate strength and flexibility, this new cement system mitigates the risk of cement sheath failure throughout the life of well. It provides a long-term well integrity solution for any well exposed to a high-pressure environment.
Abstract Carbonate formations around the world and specifically in a Middle East are prone to have total losses while drilling. And the nature of the losses often related to the highly fractured formations of the pay zone. When such fracture(s) is crossed by the wellbore the lost circulation initiated and led to a drilling without a return to a surface. To avoid undesired well control event or wellbore instability and to maintain the constant bottom hole pressure the mud cap drilling strategy often used as a preventative measure. The mud cap can be either the continuous or based on some volume or time interval, depends on the local practices or the policy of an operator. The mud cap flow rate as well as mud cap mud weight are often based on the best practices, not supported by an engineering study. To understand the behavior of the drilling fluid level in the annulus while drilling with total losses the drilling bottom hole assembly equipped with annular pressure while drilling tool was used. As the drilling required to use the continuous mud cap, then the specific guideline was developed on measurement of the bottom hole pressure and further conversion of it to the fluid level. The study was performed across pay zone with one or several loss circulation zones identified. As the result it was confirmed that the used mud cap flow rate had minor to none effect on the fluid level position in the annulus and that the bottom hole pressure remained the same. It showed as well that different loss zones are behaving in a different way, what can be considered as a factor affecting their ability to be sealed. The obtained knowledge and the information should help to understand better the loss circulation behavior as well be an important step toward development of the product which may cure the losses in high fractured carbonate formations. The results of the study can be implemented in any other project or a field.
Wide varieties of roller cone bits are available. They provide optimum performance in specific formations and/or particular drilling environments. Modern drill bits incorporate significantly different cutting structures and use vastly improved materials, resulting in improved bit efficiency. Manufacturers work closely with drilling companies to collect information about their bits to identify opportunities for design improvements. To achieve these goals, bit designers consider several factors. Replace this text with a brief (3-4 lines) introduction to what is covered on this page. Replace header name above, then begin creating your text in place of this text. To make subheads to this heading, use the Heading level 3 style from the drop down.
Since the early 2000s, the number of Floating Production, Storage and Offloading (FPSO) units is increasing significantly. And so now, half of the fleet is over than 10 years old. As FPSO are mainly installed in tropical areas, with marine environment, high temperature and high humidity, corrosion is a permanent threat. Maintenance of steel structures become a challenge for oil major companies in offshore operation. Indeed, when allowable corrosion limit are reached, plates are to be repaired. However the current “crop and renew” technique implies a number of major issues for owners such as: “hot work”, i.e., welding; temporary structure weakening; necessity to empty, clean and vent oil tanks, leading to a long down time and an expensive solution. “Cold repair”, such as bonded repair, is an obvious solution, due to a short down-time and non-intrusively process. However, currently no standards or rules exist for this kind of repair and engineering faces problems as basic as strength qualification. To address the lack of knowledge on the strength assessment of bonded repair for primary structure, Bureau Veritas Marine & Offshore launched a Joint Industrial Project (JIP) named StrenghBond Offshore with oil companies, shipyards and suppliers. The main objectives of the JIP are to: Assess short term and fatigue strength of typical bonded repairs, Enrich knowledge of adhesive joints strength on typical offshore repairs cases, Enable a better evaluation of the margin between the actual strength of a repair and the design load, Validate the characterisation procedure for strength prediction of bonded assembly, Define a robust strength prediction method, Gather the collected experience in a industrially applicable guideline, Standardise qualification process for offshore composite bonded repairs. The project intends to provide a design approach for bonded reinforcement that is design orientated, accurate and recognized by the offshore industry.
Summary In this paper we present a methodology to superimpose the American Petroleum Institute (API) uniaxial and triaxial limits on tubular design limits plots (API TR 5C3 2018). Complications caused by a recent change of axis are resolved, producing a practical design limits plot that avoids the horizontal shift of the API vertical limits, which is currently the industry standard. The commonly used slanted ellipse is compared against an adaptation of the circle of plasticity in the form of a horizontal ellipse, showing the convenience of this last one with examples. After the current official collapse formulation was made part of the main body of standard API TR 5C3 (2018), the horizontal axis on the standard industry well tubular design limits plot changed. The present study evaluates this redefinition of the horizontal axis. One consequence of this modification is a difficulty plotting the API tension and compression limits. The API horizontal limits (uniaxial burst and collapse) are found to be independent of load situation, whereas the API vertical design limits (uniaxial tension and compression) are dependent on inside and outside tubular pressures. The approaches used by commercial software and industry publications to solve this challenge are reviewed. A new design methodology is developed to link API uniaxial limits to the triaxial theory. One main objective of the study is to establish a mathematical relationship between API tubular design limits and the von Mises triaxial theory (API TR 5C3 2018). A methodology that allows plotting the API uniaxial force limits on the design limits plot is developed. The study also shows that the results obtained from the industry standard slanted ellipse are identical to those obtained from the horizontal ellipse and circle. One important difference is that the slanted ellipse is based on the zero axial stress datum, whereas the horizontal ellipse/circle uses the neutral axial stress datum. The horizontal ellipse/circle is well suited for calculations involving buckling, compatible with the information used in field operations, and its formulations are less complicated than the tilted ellipse. Therefore, attention is called to the use of the horizontal ellipse/circle in well tubular design.
Eid, E. (University of Stavanger) | Tranggono, H. (University of Stavanger) | Khalifeh, M. (University of Stavanger (Corresponding author) | Salehi, S. (email: firstname.lastname@example.org)) | Saasen, A. (University of Oklahoma)
Summary Our objective is to present selected rheological and mechanical properties of rock-based geopolymers contaminated with different concentrations of drilling fluids. The possible flash setting and the maximum intake of drilling fluids before seeing a dramatic deterioration of the geopolymers are presented. Rock-based geopolymers designed for cementing conductor and surface casing were prepared and cured for up to 28 days at 22°C and atmospheric pressure. Water-based drilling fluids (WBDFs) and oil-based drilling fluids (OBDFs) were designed in accordance with the recommendations from the petroleum industry. The fluid samples were prepared, and their viscous behavior was characterized before and after hot-rolling. The geopolymeric slurries were mixed and then blended with the prepared drilling fluid volumes. The contaminated geopolymeric slurries were cured and tested at different time intervals. American Petroleum Institute (API) Class G neat cement was used as a reference. These samples were cured and contaminated with the same drilling fluids. The properties of contaminated geopolymer slurries were benchmarked with those of the contaminated Class G cement. The obtained mechanical properties showed that the rock-based geopolymers are more sensitive to WBDFs than to OBDFs. However, for contaminated Portland cement samples, the obtained results were opposite, and the contamination effect of OBDF on cement was more noticeable than WBDF. The impact of geopolymer contamination is a function of curing time. Although geopolymeric samples showed dramatic strength retrogression at the early time, strength buildup of the samples compensated for the impact of contamination.