Oil and gas companies across the spectrum are moving toward digitalization. Leveraging technology to access real-time data has allowed companies to streamline activities and gain operational efficiencies while at the same time improving worker safety by reducing the number of personnel required offshore. This evolution optimizes operations by enabling better decision-making by subject matter experts (SMEs) located around the world working as one interconnected team. Functions once performed exclusively by offshore personnel are being carried out today by onshore workers via remote technology. By capitalizing on the ability to communicate offshore via high-speed internet, it is now possible to carry out ROV operations using a team that includes onshore based personnel. A recent project illustrates how ROV activities controlled from an onshore remote operations center in Louisiana were carried out successfully on a production Tension Leg Platform (TLP) in the Gulf of Mexico (GoM). The technology used onboard the TLP is not new; operators have been remotely managing a range of functions on offshore assets for years. However, the project does apply this proven approach to ROV piloting operations for the first time commercially in the GoM. Transferring ROV control from the offshore platform to a facility onshore is possible using a communication link that connect real-time data from the offshore asset to the onshore remote operations center (OROC). The two-way communications link provides a redundant system in which controls can be executed either from the offshore platform or from the remote operations center, allowing specialized roles that historically have been executed offshore, including that of the ROV pilot, subsea engineer, and company representative directing the work, to be transferred to a land-based team. The increase in data required from the offshore asset for the GoM project was managed via a dedicated link that provided data transfer at a minimum speed of 3 Mbps upload/download with a fail-safe system that automatically default control to the offshore ROV team in case of any failures in the communication link. Remotely piloting an ROV from shore and coordinating with an offshore crew not only delivered a reduction in HSE exposure but reduced overall personnel costs on the asset by more than 30% for 24 hours of operations. This approach to ROV operations has the potential to reduce costs by reducing the number of workers required offshore even further if additional staff associated exclusively with the project subsea work scope is directed to work remotely from shore.
In order for capital-intensive deepwater prospects to remain at investment grade potential, it is important the industry achieve meaningful improvement in capital efficiency. Achieving this goal will require a multi-faceted strategy in which advanced new technology and digital transformation will play a determining role. This paper will address the optimization of rig operations through deployment of an advanced Remotely Operated Vehicle (ROV) system that leverages precision robotics and automation technologies; reducing total cost of ownership (TCO) through increased rig productivity, operational certainty and overall utilization. Current ROV technology faces several key limitations which contribute to both schedule and cost variation. These inefficiencies are a combination of human skill variance, ROV system limitations and reliability. Advanced ROV systems have been deployed on two deepwater rigs to demonstrate that machine vision and precision robotics technologies will radically improve the predictability and efficiency of operations. Comprehensive metrics addressing safety, budget impact, cost avoidance & reduction, inventory reduction & non price TCO have been developed to capture the efficiencies and identify the net improvement to drilling and completion operations and yield outcome-based performance. An overview of the key deficiencies and limitations of legacy ROV operations will be conveyed, focusing on; i) High dependency on ROV pilot subsea task skills, ii) Worksite efficiency and ROV availability, iii) Restricted tooling capabilities per dive, iv) Rental tooling logistics and cost, v) Equipment reliability at depth, vi) Inefficient tooling changes, and vii) Dive duration and lost time efficiency launch/recovery time. An overview of how the advanced ROV system resolves these issues will be explained. In addition, an explanation of the productivity metrics will be conveyed, supported with data from the active offshore projects. Key conclusions from the data identify that enhanced robotics will achieve the objectives of i) Reducing schedule and cost risks which improve total cost of ownership, ii) Enhancing capability and improved wellsite efficiency, and iii) Increasing subsea data. The performance issues of legacy ROV operations and associated project cost impact is currently not widely recognized by the offshore drilling community. The realized limitations of such ROV operations and lack of useful performance metrics to identify non-productive time will be explained. The progression in robotic design that drives a new era of subsea robotic efficiency will be conveyed with results from offshore operations, combined with robust metrics that enable significant operational value and cost savings to be attained.
The Phase 3 wells of the BC10 Parque Das Conchas field were drilled and completed in the Campos basin offshore Brazil in water depths between 1600-1900m. The wells were delivered as part of a batch campaign, 4 months ahead of schedule and approximately 40% under budget. The development campaign consisted of 7 horizontal wells (plus a side-tracked appraisal section). This paper will describe some key replication considerations at a planning, operational and organisational level that enabled the delivery of performance that benchmarks in the P5 range of the industry in both schedule and cost. Essential catalysts for this performance included the immediate, repeat use of the 6th generation DP drillship MODU from the earlier Phase 2 campaign, standardisation of the well design and procedures, operating in ¨total batch mode¨, continuity of staff over the entire 4 year campaign lifetime and targeted contract incentivisation. With these components fixed, focus could be applied to both actively reducing Invisible Lost Time using Deliver the Limit methodologies, and NPT by way of rigorous and monitored QAQC and maintenance programs, leading to this high quality performance result.
An alternative methodology using new preventative technology to manage cybersecurity exposure on deepwater drilling rig assets is presented. For the past two years Shell's Deepwater Wells business has been evaluating typical cyber defence approaches and undertaken cybersecurity risk assessments and penetration tests. These activities have demonstrated the challenges attaining cybersecure drilling rig environments. Whilst cyberattacks increase in frequency, adaptability, and become cheaper to launch, regulatory and liability insurance requirements are also evolving. To achieve the goal of cyber-resilience, a major Operator has collaborated with a cybersecurity firm to trial technology for rapidly and reliably protecting deepwater rigs. The paper presents aspects of the numerous challenges faced and offers a different approach using new technology applied to both supplement and accelerate the attainment of a cyber-resilient environment onboard deepwater drilling rigs. It shares the deep dive lessons learnt leading to a more comprehensive understanding of how to protect drilling rigs and their safety critical control systems. Aside from addressing technical attributes using risk vs. maturity based methods, the approach also caters to business demands of short term rig contracts, managing multi-vendor legacy systems and satisfying increasing digitalisation/remote access needs with associated reductions in overall cybersecurity CAPEX spend.
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