This paper focus on factors attributing to casing failure, their failure mechanism and the resulting failure mode. The casing is a critical component in a well and the main mechanical structural barrier element that provide conduits and avenue for oil and gas production over the well lifecycle and beyond. The casings are normally subjected to material degradation, varying local loads, induced stresses during stimulation, natural fractures, slip and shear during their installation and operation leading to different kinds of casing failure modes. The review paper also covers recent developments in casing integrity assessment techniques and their respective limitations.The taxonomy of the major causes and cases of casing failure in different well types is covered. In addition, an overview of casing trend utilisation and failure mix by grades is provided. The trend of casing utilisation in different wells examined show deep-water and shale gas horizontal wells employing higher tensile grades (P110 & Q125) due to their characteristics. Additionally, this review presents casing failure mixed by grades, with P110 recording the highest failure cases owing to its stiffness, high application in injection wells, shale gas, deep-water and high temperature and high temperature (HPHT) wells with high failure probability. A summary of existing tools used for the assessment of well integrity issues and their respective limitations is provided and conclusions drawn.

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Objectives April 2010 in the Gulf of Mexico and January 2017 in Oklahoma brought into sharp focus what can happen if the oil and gas industry gets well control wrong: 16 fatalities, significant environmental damage, loss of assets and reputation. Each year we have multiple blowouts and several fatality events due to a loss of well control. The oil and gas industry can improve from a personnel safety, environmental and reputation perspective. The Automation of Well Control will bring a significant step change in the area of Process Safety forwells. It prevents blowouts, reduces all influx volumes, minimising kicktolerance volumes and reducingcasing and well costs. Method A system has been developedwhich enables Automated Well Control whilst in drilling mode. Pre-determined influx rates, agreed by the operator and drilling contractor, and input by the driller are established. Once the system detects the influx, it performs a series of operations by taking control of the drilling rig equipment. The drill string is spaced out, top drive and mud pumps are stopped, and the BOP is closed. All of this occurs without the driller doing anything; however, he can intervene at any moment. Thissystem is designed as an aid to the driller and does not remove his responsibility. Results The Automated Well Control system has been tested on drilling simulators with real drillers. Comparisons tests have shown that the technology enables shut-in times faster than conventional human interface methods, with influx volumes typically 10-20% of those experienced during manual shut-in. Additionally, a full Field Trial using a traditional rigdemonstrated the effectiveness of the system, proving up the functionality under different operational requirements. The system can now be applied to any type of rig worldwide. Over 50 potential modules have been identified. Planned developments forthe system include circulatingout the kick automatically, shut-in for tripping, circulating, cementing and in-flow testing. It provides assurance for afast, safe and effective shut-in.A full Technology Qualification process has been used for this technology. Innovative Technology Over the past 20 years, technology advancements associated with simulators and cyber-rigs have enabled new technologies to be developed. One of these technologies is Automated Well Control. It is believed that this innovative system will enable a step change in the performance ofprocess safety forwell control, dramaticallyreducing major accident hazards, thereby saving millions of dollars per well, reducing environmental impact and preventing loss of life.

Digitalisation and automation can account for massive efficiencies in wells operations. Managed Pressure Drilling (MPD) and Automated Well Control are examples of "smart" technologies that can mitigate risks and costs associated with drilling wells. The Automated Well Control system was developed to monitor the well, identify an influx, take control of the rig equipment and shut in the well. MPD provides annular pressure control, real-time information of the well parameters and conditions downhole and very accurate and immediate influx detection. However, if a high intensity influx is taken that exceeds the pre-planned operational limits of the MPD package, then secondary well control is required. Therefore, a combination of Automated Well Control and MPD has been developed to deliver both pressure control and well control in a safe, efficient and less error-prone manner. On an MPD operation, the Automated Well Control system shuts-in the well as soon as it is required to do so. With Automated Well Control in MPD mode, the MPD system decides when to shut in and the Automated Well Control technology will immediately space out, stop the mud pumps and top-drive, and shut in the well using the pre-selected blowout preventer. This interface between the two systems mitigates drilling hazards using automation. The sensitivity of MPD, combined with Automated Well Control technology enables fast identification, decision making and reaction to well control events. Consequently, this fully integrated solution improves safety and operational efficiency. The MPD and Automated Well Control systems were integrated into a test rig and several tests were efficiently performed. The tool enabled immediate action in the event of influxes, providing a valuable solution for the industry. This paper briefly describes MPD and Automated Well Control and summarises the interface between the two technologies, detailing how the integrated system works on a rig. Moreover, rig trialling results and further developments are presented.

Tradionally, well control systems have been entirely reliant on a single human reliably and accurately detecting an influx and shutting-in the well.  The human condition means the driller can be distracted, or unexpectedly influenced by extraneous factors. Over-reliance, then, on humans in well control can be dangerous, because of the inherent and constant exposure to human factors risk. An automated well control system has been designed to fully automate influx detection and shut-in sequences and reduce personnel exposure to rig-floor safety risks. A comparative human factors study for the use of automated well control against traditional well control methods was performed. The analysis, completed by means of Human Reliability Assessment methodology, provides a qualitative and quantitative assessment of the human failure modes associated with the operation of the automated well control compared with the equivalent associated with traditional methods. A Systematic Human Error Reduction and Prediction approach was used to provide the basis for subsequent quantitative assessments of human reliability. Once scenarios were subjected to the qualitative modelling process, the Success Likelihood Index methodology was applied to quantify the human error probabilities.   The outcome of the comparative analysis highlights a significant reduction in the human failure risks that automated well control brings to well control. By examining the opportunities for human error/failure to impact upon the successful identification and shut-in of an influx, the study demonstrates that automated well control could achieve 94% reduction in the probabilities of human failures for a blowout, or 96% for a large influx. This paper will describe the automated well control technology and summarise the outcomes of the comparative analysis between automated well control and traditional well control.