In the today high-cost and complex drilling environment, the importance of drillstring failure issue has dramatically reappeared, in spite of many manufacturing and materials improvements. Most drillstring failures are due to fatigue, resulting from repeated cyclic bending loads and stresses in tensile or buckled drill pipes. Fatigue prediction is usually based on the cumulative fatigue damage model from Hansford and Lubinski as defined in API RP7G. This model, based on S-N curves, a failure criterion and a damage accumulation rule, initially requires a calculation of the drillpipe stress caused by bending when rotated in a dog leg. This bending stress calculation, key point of the cumulative fatigue damage model, is usually made by assuming that the curvature of the drill pipe is the same as the dog leg. However, this paper shows that this strong hypothesis may lead to major under-estimation of the cumulative fatigue damage. Moreover, the stress distribution within a drill pipe may be completely different depending mainly on the position of the drill pipes along the drillstring and the wellbore architecture and tortuosity. The cumulative fatigue damage model as defined in API RP7G has been implemented in an advanced torque and drag model, which enables to track any given point of the drill pipe while drilling, such as the transition zone, the tool joints and the drill pipe body. For the first time, it has also been possible to fully track variation of stresses at a given point in the drill pipe. Based on drill pipes S-N curve available in the literature and actual drilling data, this paper shows and compares results of fatigue damage calculations as obtained from the conventional way (strong hypothesis on the contact) with results obtained from advanced torque and drag model that make no assumptions about the contact. This extensive study as presented in this paper has never been done in the past. This advancement should probably lead to minimize the risk of drillstring failures in complex wells by a better monitoring of stresses in drill pipe. Introduction Drill pipe failures are still responsible for rising costs in drilling industry. In spite of many research studies carried out to mitigate this issue, it continues to occur with high frequency. Many drill pipe failures analyses have shown that fatigue accounts for the majority of drillstring failures. Fatigue is a cumulative and non-reversible phenomenon, resulting from repeated cyclic bending loads and stresses in tensile or buckled drill pipe. Fatigue occurs even if the cyclic stress is much lower than the static strength limit of the drillpipe material. Fatigue prediction is based usually on the Cumulative Fatigue Damage model (CFD), introduced by Hansford and Lubinski in API RP7G1. This model allows determining the life duration of the drill pipe based on S-N curves, damage accumulation rules and a failure criterion. However, it requires calculation of the drill pipe stress in the wellbore, which is the key point in fatigue prediction. Bending stress calculation has first been performed by Lubinski in case of rotated drill pipe subjected to tension, and Paslay suggested improvement by studying the case of compression. Lubinski/Paslay model is based on strong hypotheses on the contact between drill pipe and wellbore, and assumes the axial load to be known. The aim of this paper is to address a new approach to assess the bending stress in the drillpipe. This methodology allows implementing the Cumulative Fatigue Damage model as defined in API RP7G, in an advanced torque/drag and buckling model 2,3,4, which allows tracking any given drill pipe while drilling.

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Globally, there are numerous offshore legacy assets, including offshore platforms, subsea infrastructures, and wells that exist, however, are at or approaching their end of life and require decommissioning. Within the range of infrastructure, there is a subset of assets that are categorized as complex to decommission due to being unable to either gain access to the wellbores from the surface with offshore drilling units or there exist casing integrity issues which restrict the ability to access the wellbore. This paper will outline methods that can be applied in the offshore environment to successfully and economically decommission these assets using sub-surface intervention technology. The long-term environmental impacts of not taking action on these assets can be significant, and up until now, the problem has faced economic challenges and high technical risks to remedy. The methods for complex decommissioning are drawn from a history of relief well intervention and onshore complex plug and abandonment. This paper will outline the methodology required to lower the risk of offshore complex decommissioning. The methods presented utilize active and passive magnetic ranging technology with no access to the target wellbore. Experience on land-based operations has proven the methodology for complex decommissioning challenges, which enables wells to be abandoned economically with highly successful outcomes. The process is a permanent remedy to intervene and abandon wellbores mitigating environmental impacts and enabling operators to satisfy the growing change in perception with regards to the environmental obligations of the oil and gas industry. The methods and technology applied for permanent decommissioning of subsurface assets have been optimized for offshore operations. These processes ensure that the economic cost is controlled through the application of risk-based methodologies and a proven, consistent approach to the execution of the operations. The active and passive magnetic ranging systems are undergoing a constant research and development process to further optimize the operations with the novel methods being shown in this paper.

A new joint venture operator, established to take over an existing strategic producing field with ongoing drilling operations, took the opportunity to design a new collision avoidance standard, based on the latest WPTS (Wellbore Positioning Technical Section) probability method collision avoidance rules. This has been combined with an innovative execution approach to safely and successfully unlock slots on congested platforms and drill some of the most difficult well trajectories in this complex field from the very first well. Al Shaheen field, offshore Qatar, is one of the most challenging fields worldwide in terms of collision avoidance. When drilling extended-reach wells from the last-remaining and most challenging slots, with top-hole separation as low as three feet centre-to-centre at the conductor pipe shoe, close collaboration with all parties is required to manage collision risk, minimise production loss, and ensure all well objectives are achieved. The execution strategy includes simple jetting and rotating BHA designs for 3D-profile trajectories, remote real-time monitoring including 24/7 survey QA/QC and validation, and mitigation through a decision-making matrix customised for the specific drilling challenges. The platform configuration and challenges in the drilling environment are discussed, together with the theory of the selected collision avoidance rule and the resulting risk matrix. A brief review of why jetting is selected as the only allowable drilling technique in major risk situations plus the story of the evolution of Al Shaheen jetting BHAs follows. Finally, three case studies of top-hole operations describe the practical application of the techniques discussed. The selected case studies describe the jetting operation from the deepest CP (Conductor pipe), the deepest well jetted, and the first 23-in jetting operation carried out by the operator. The combination of risk analysis through genuine probabilistic considerations, jetting operations, and appropriate oversight has been used successfully for more than two years and has allowed over twenty of the remaining, most challenging, slots to be saved, ensuring the assets are optimised in the ongoing economically-constrained environment. The WPTS have now published their proposed industry-standard probability-based collision-avoidance rule. These case-history examples of a similar rule from extreme close-approach drilling will assist other operators considering uptake of the new guidelines, as will the risk matrix developed by the operator. In addition, the jetting technique used as a major mitigation factor is seldom used today in the industry and the lessons learned in jetting BHA design have already benefited another operator in the region.