Metal-ceramic coatings have been widely used for industrial applications, mainly in the gas turbine and diesel engine industries as thermal barrier coatings (TBCs). Conventional thermal barrier coatings consist of a metallic bond coat and an insulating ceramic topcoat. Temperatures and temperature gradients in the coating during plasma spraying play an important role on the final coating quality, especially the temperature of the particles just hitting the substrate surface. In this work, metal-ceramic coatings were applied on nickel-superalloy substrates. The temperatures of both the coating surface and substrate were measured during spraying. The adhesion of the coatings was determined using ASTM C 633 and correlated with the measured temperatures. Optical pyrometry and thermocouples were used to measure the interfacial and substrate temperatures, respectively. Temperature was shown to have a significant influence where lower interfacial temperatures were found to result in lower adhesion values.

Recent development of a new dynamic model for tubular stress analysis is now extended to the design challenges and failure modes characteristic of long production casing strings in extended horizontal shale wells. In particular, the issue of cyclic loading due to repeated sequences of multi-stage fracturing has not been addressed until now. The new model provides the ideal means of analysis of cyclic thermal loads as well as critical impact of compression due to initial running friction. The new dynamic model of tubular stress solves the one-dimensional momentum equation over a time step sequence initiated from the original running of the string into the wellbore. Friction is modeled in a fully history dependent manner, with damping provided naturally by the wellbore fluid viscosity. Local pipe velocity as well as magnitude and orientation of sliding friction is solved at each node with friction aggregated at the connection upset and joint mid-point. Unconventional shale wells pose critical design challenges especially in regard to the long production casing strings run in extended horizontal or lateral sections. Compressive frictional loads accumulated during running are trapped in the string by cement, packers and the wellhead. Thus the initial load state must fully account for the initial frictional state in order to be realistic and conservative. Hydraulic fracturing at high flow rates and significant pump pressures, including the possibility of screen-out, represents a critical design load on the casing which can also significantly alter the orientation and magnitude of tubular/wellbore frictional contact. The particular phenomenon of repeated fracturing treatements in a multi-stage stimulation compounds the design challenge. Cycles of cold stimulation followed by renewed hot production can lead to unexpected migration of axial loads and localization of critical stresses. The cyclic nature of loading due to repeated sequences of multi-stage re-fractures and renewed production has not received industry attention due to the unavailability of appropriate models. Lack of adequate models has perhaps resulted in the problem being overlooked. A dynamic model is ideally suited to the analysis of cyclic loads because of its inherent ability to account for a full history of friction loads. The dynamics of loading and unloading are also critical to this new ability to address the design problem. Previous static-based stress models have been unable to provide a comprehensive basis of design.

A new dynamic model for casing and tubing design with friction has been developed. This paper applies the model to a field case study, an actual installation of a single trip, multizone completion in an offshore highly deviated ERD well. This is the first application of a comprehensive model with complete friction history to both installation and in-service loads. The field case demonstrates the results of a novel dynamic model for tubular stress and displacement with changing friction loads. Recorded hookload data during completion running and calibration of effective wellbore friction coefficients provided validation of the model. Accumulation of localized stresses at critical well locations is considered. The sensitivity of worst case downhole forces to the order of operational life cycle loads including stimulation, production and gas-lift was assessed. Stresses and displacements associated with each step of the setting process for multiple isolation packers were simulated. Theory and detailed description of the dynamic model are presented in an associated paper. A dynamic model of tubing forces is necessary to predict local pipe velocity which in turn determines the magnitude and direction of the local friction vectors. Distribution and orientation of wellbore friction contact is determined by the pipe running events but then is subject to change as cement and packers are set and as downhole operating conditions change. Order of life cycle conditions such as stimulation followed by production versus production followed by workover has significant impact on the magnitude of forces at worst-case locations. The investigation included the change in tubing wellbore frictional contact when completion brine is displaced with dry injection gas in conversion to gas-lift. The model demonstrated the significance of a different order of linked operations and showed that the standard available analysis tools may overlook or fail to identify worst case loads. Potential for acute load localization due to successive stimulation and production events was quantified. Impact of migration of friction loads during cyclical load events was also evaluated. The predicted initial axial load profiles were verified with recorded hook loads and corroborated with standard torque and drag model results. Comparisons are made against a previously published analytical technique. For the first time, a dynamic friction model enables seamless integration of running loads into a fully sequential analysis of subsequent well life cycle loads for landed strings. Current industry models tend to separate installation loads from the in-service life envelope. Ability to predict the changing friction orientation on installed tubulars is significant. Modelling life cycle loads in true sequence provides more accurate results for tubular design and enables a true analysis on the real-world order of well events.

Casing design and the associated load assumptions have evolved considerably over the last 30 years. The objective of this paper is to trace the history, evolution and future of casing design by means of the type of load cases and the assumptions made for them as it evolved from the early 1960's to the modern load case requirements for wells drilled in the 2020's. The vast majority of tubular failures in oil & gas wells are not attributable to computational errors in calculating design loads, but rather are due to a shortfall in considering the appropriate load scenarios. One common shortfall includes making incorrect or oversimplified assumptions for the initial and final temperature and pressure conditions. There is no industry standard for casing or tubing design loads, but there is an industry accepted standard process for the calculation of the stress on tubulars once the load cases are determined. Each operating company may use a different set of load assumptions depending on the well type and risk assessment. This work also keeps in view the major computational tools used during each step change of the casing design evolution: slide rule/nomographs, HP 41C calculators, PC DOS and Windows programs, and the latest Cloud-Native paradigm with REST API's within a microservices architecture. A REST API (also known as RESTful API) is an Application Programming Interface (API) that conforms to the constraints of Representational State Transfer (REST) architectural style commonly used in current Cloud computing technology. The scope will also include ongoing research and development to address shortcomings of previous load case assumptions and calculations for extended reach and HPHT wells, closely spaced wells, and geothermal wells. Modern wells and modern casing design load cases are in a constant state of evolution and casing failures will occur unless engineers and their tools also evolve.

The wellbore and formation temperature environment around a system of multiple wells in close proximity is complex. Temperature simulation and prediction for a single isolated well is simplified by axisymmetric assumptions. Realistic multi-well environments do not have obvious symmetry and are interactive given different operating states including possibly a mix of producer versus injector wells. A simulation model of thermal interaction between closely spaced wells has been developed in a collaborative project. A large-scale validation of the model is presented here. An important field application is presented for a subsea well template where movement tolerances must be tightly controlled. Large-scale validation was conducted for an offshore platform development where more than 30 wells were drilled and brought onto production over a period of 4-5 years. As each well was drilled and completed, temperature logs where recorded which thereby gave a digital signature of the complex thermal environment below mudline as it evolved over time. The simulation model temperature for each well was corroborated against well temperature logs. A simultaneous boundary-condition of flowing wellhead temperatures and pressures for each well was compared against the model predictions. Also, a detailed predictive case study is presented for a 6 well subsea template. Model temperatures were used to assess the impact of cement height on wellhead movement within the template structure which featured lockdowns and tight tolerances on allowable movement within the housing profile. Predicted temperatures from the multi-well model agree closely with logs and correlate closely with characteristic temperature excursions from geothermal below the mudline down to the well path kick-off zone. Since the logs occur over time and account for a changing well population, the model is shown to accurately capture the time evolution of the complex temperature environment. The model explains unusual temperature log signatures as the result of sidetracks and the radial extent of heat affected zones from the parent wellbore. The subsea case study highlights the importance of predicting the complex multi-well temperature environment by demonstrating its impact on the wellhead movement given the uncertainty of cement tops for deeper shoes of combined conductor/surface casings. This learning informs subsea template design and selection with port options for cement grout and top-up jobs. Although the multi-well temperature model has been presented previously along with some field data validation, the large-scale study presented provides further and significant model validation. Extensive data over time and corroboration with unusual temperature log phenomena demonstrate model accuracy. The utilization of the model in the design and specification of a subsea template development provides a real-world example and demonstrates practical application as well as its usefulness.