casing wear
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Abstract The forces and stresses along casing strings are modeled using a stiff string torque and drag model. The effect of wellbore tortuosity and centralization are quantified in preplanning phase in addition to the effect of 3D orientated casing wear. A realistic case study is presented to show the resulting effect on axial, burst, collapse and Von Mises equivalent (VME) safety factor as well as VME body and connection design envelopes. While running a tubular downhole, a smooth wellbore is normally assumed when performing a torque and drag calculation. In reality, the inherent tortuosity of the wellbore which is caused by the drilling process can cause significant local doglegs. When applying a soft-string torque and drag model, the stiffness, radial clearance and high frequency surveys needed to fully model local doglegs are rarely modeled. The stiff string torque and drag and buckling model can model these effects, as well as the addition of rigid and flexible centralisers. This study involves the comparison of different casing design load cases, under different centralizer programs and tortuosity taking into account a 3D orientated casing wear. The results show that there can be significant differences in overall axial stress depending on the centraliser program and tortuosity used. The soft string model doesn't directly account for bending stress, normally this is estimated using a Bending Stress Magnification Factor (BSMF). In contract the stiff string model can directly calculate the additional bending stress. This additional stress can be particularly prevalent while RIH casing with centralisers and high tortuosity. The reduction in American Petroleum Institute (API) and VME stress envelope is also quantified using a 3D orientated casing wear model. A better understanding of axial stress state reduces risk of well integrity issues. This paper will show the benefits of using a stiff string model, considering additional contact points, bending stress as well as the benefits of modelling tortuosity and centralizer program early in the design process. During extended reach drilling (ERD) and high-pressure, high temperature (HPHT) wells, this information can be critical when correctly assessing the axial stress state.

Summary Casing wear is the process of progressive loss of wall thickness owing to relative motion between the drillstring and casing. The amount of casing wear depends on conditions, such as the downhole forces, the accumulated time of contact between drillstring and casing, and the materials used. This process is complex and involves abrasive, adhesive, and corrosive wear mechanisms that are difficult to predict. To deal with the complexity of the conditions, a simple but effective wear model is used in the industry to estimate tubular wear in drilling and intervention operations. The model is based on abrasive and adhesive wear, and the effects of corrosion are not considered. In addition, an empirical part of the model known as the correction factor is based exclusively on experimental carbon-steel test data. Tubulars made of corrosion-resistant alloys (CRAs) are known to exhibit abnormal wear characteristics. A series of experiments has been designed and performed to investigate the wear characteristics of CRAs. These experiments resulted in excessive wear factors for the CRA casing samples, demonstrating their susceptibility to wear. This study finds that omitting the correction factor from the calculation procedure can greatly improve wear estimates for some CRAs. Removing the correction factor results in a linear wear-work relationship that reflects the actual wear trends from test results. However, further studies are needed to confirm correction factors and more accurate wear calculation procedures for CRA tubulars in general.

Abstract Casing wear is an essential and complex phenomenon in oil and gas wells. Research is being conducted to predict this phenomenon. This study was conducted at a well in southwestern Iran. In this paper, first examine the force exerted on the drill string. Next, the contact force between the drill string and the casing is calculated. Finally, the wear volume and the depth of the wear groove are determined. These calculations were performed using MATLAB and Python software. In addition, due to the high accuracy of coding, mud log data was used to make the results more accurate. It has also been shown that increasing RPM increases the depth of wear and attempts to drill a highly deviated wells as a sliding mode. Finally, compared the results and matched them with the wireline logs recorded from the well.

Abstract Objectives/Scope This paper will present predicted vs. measured wear for six wells that were analysed in the Culzean field, which is a high-pressure, high-temperature (HPHT) gas condensate field located in the central North Sea. The focus rests on the casing wear prediction, monitoring and analysing process and within that, especially on how to make use of offset data to improve the accuracy of casing wear predictions. Methods The three major inputs to successfully predict casing wear are: Trajectory & Tortuosity, Wear Factor and required rotating operations. All those were calibrated based on field measurements (High-resolution gyro, MFCL (Multi-Finger-Caliper-Log) and automatically recorded rig mechanics data), to improve the prediction quality for the next section and/or well. The simulations were done using an advanced stiff-string model featuring a 3D mesh that distinguishes the influence of different contact type and geometry on the wear groove shape. The "single MFCL interpretation method", in which the wear is measured against the most probable elliptical casing shape and herby allowing wear interpretation with only one MFCL log and avoiding bias error, was applied. (Aichinger, 2016) Results, Observations, Conclusions For the six wells that were analysed the prediction of the largest wear peak per well section was compared to the measurement. In the planning phase (before any survey data was available) the mean error on the wear groove depth was +/− 0.025 [in] (+/− 0.6 [mm]), the maximum error was +/− 0.045 [in] (1.1 [mm]). The average error of the results is summarized in Figure 10 and laid out in detail in Figure 9. Generally, the predictions are accurate enough to be able to manage casing wear effectively. In this particular case, the maximum allowable wear on the intermediate casing was extremely limited to ensure proper well integrity in case of a well full of gas event while drilling an HTHP reservoir. Novel/Additive Information This paper should provide help to Engineers who seek to improve the accuracy of casing wear prediction and hence improve casing wear management. It presents a new way of anticipating tortuosity based on offset well data and it offers a suggestion on how to deal with MFCL measurement error during Wear Factor calibration and Wear prediction.

Abstract Predicting casing wear has often been regarded as an empirical art as there are many influencing factors, including but not limited to the sizes and grades of the drill pipe and casing, type of hardbanding, drilling fluid properties, rate of penetration, trajectory and formation properties. Formations present in offshore Western Australia often contain loose and friable sands which produce highly abrasive cuttings which, when suspended and circulated in drilling fluid, are known to exacerbate casing wear. Casing wear is considerably worse in deviated and multilateral (ML) wells; Woodside's experience drilling ML wells has involved costly non-productive time (NPT) due to the subsequent requirement for remedial tieback systems to maintain well integrity. In 2018 and 2019 three tri-lateral wells were drilled as part of the larger Greater Enfield Project drilling campaign. Each of the multilateral wells were progressively longer and more challenging with regard to casing wear. Previous experience on nearby wells in analogous fields identified casing wear as a significant risk for the project. Further to this, an opportunity was identified to design the longest tri-lateral well as a quad-lateral well, which would allow increased recovery if reservoir quality was poorer than expected. The Drilling and Completion Engineering team were challenged with proving that casing wear could be effectively evaluated and managed during operations to allow a quad-lateral well design if required. Several key areas were investigated in order to effectively manage casing wear. These included: Assessment and measurement of casing manufacturing tolerances;Predictive casing wear modelling using well offsets in conjunction with casing wear software;Casing connection finite element analysis and mechanical hardbanding testing;Full length ultra-sonic testing of casing for wall thickness benchmarking;Hardbanding management plan (which formed part of the overall drill pipe fatigue management plan);Casing wear management plan based on well offsets and casing wear software modelling results, including additional controls such as 'krev' and swarf monitoring;Planning and execution of casing wear logging;Post well evaluation. The casing wear operational plan was effective in monitoring and limiting the amount of wear. It provided confidence to the management team that successful execution of a quad-lateral well was feasible. This paper will describe the steps taken to minimise casing wear, discuss comparisons between the predicted wear and the actual measured casing wear, and provide a recommended workflow for predicting casing wear in future wells where casing wear is a critical factor.

Drillstring vibrations can be undesirable for drilling operations. Here, attention is focused on vibrations of the upper portion of a drillstring as these vibrations can cause drillpipe wear and casing wear. A reduced-order model is developed to study the motions of a drillstring by taking fluid loading and stabilizer effects into account. In this model development, the distributed nature of the fluid loading is taken into account, and the drillstring is treated as a beam structure. Perturbation analyses are carried out with the reduced-order system, and the system responses are examined for primary and secondary (subharmonic and superharmonic) resonance excitations. The analytical-numerical results reveal the rich nature of the system behavior and help understand the drillstring motions during various resonance conditions.

Abstract The UHP exploratory well subject of this study faced with myriad challenges, including fishing, side-tracking, and other undesirable incidents with consequences to the 9-7/8" production casing. Torque and drag analysis, preliminary casing wear simulations, and actual drilling parameters pointed towards multiple uncertainties concerning barrier integrity. Consequently, a multi-physics evaluation was conducted including well-integrity logs in a combination of thickness-mode with flexural-mode of the casing. Signals from these independent measurements are then processed to provide robust interpretation of solid-liquid-gas behind casing using acquired flexural attenuation and acoustic impedance data. In addition, casing wear is quantified by thickness changes measured through the resonance frequency of the waveform and represented in the form of a joint-by-joint corrosion summary, reporting the average metal loss. Furthermore, propagation of flexural wave-fronts as it leaks to the third interface is tracked to produce a unique image of the annulus geometry in terms of casing eccentricity and acoustic velocity of the medium. Subsequently, the former, provides a quantifiable, unique in-situ casing standoff measurement to be used for centralization evaluation. Application of the developed data-integrated workflow allowed for comprehensively analyzing well integrity barrier condition. Cement barriers were assessed with confidence by flexural imaging, which were difficult to determine solely with pulse-echo. Additionally, annulus imaging using third interface-echo (TIE) helped in characterizing the potential causes of casing wear and quality of cement behind casing by providing actual in-situ casing standoff. It was observed that casing wear was at the low side of the wellbore where the casing had the least standoff as shown by flexural waveform TIE arrivals. Moreover, high percentage of metal loss was correlated to regions with centralization lower than 40-50%. Integration of these results with casing side forces and remaining casing strength (under worst case scenario) was performed to evaluate casing endurance for future drilling, production, and injection operations.