This paper will provide a description of the benefits of the remote operations alternatives developed over a decade in the North Sea. Substantial support from Hydro/Statoil, starting in 1999, with remote data monitoring, re-manning the rig site with remote support, and the transfer of rig-based work tasks to a remote operations centre has changed the way we operate today and will also influence how automation will be integrated in the future. Reduction in personnel-on-board (POB) and alternative remote operational models implemented resulted in measurable reductions in cost and HS&E exposure. The paper will give a thorough description of how continuous high operational performance and efficiency gains to operations at different levels has been achieved and documented in the North Sea and translated to the Brazil environment. Other key areas for discussion are: improved performance and reliability, decreased NPT, standardized work processes, 24/7 technical support, real-time drilling optimization, cross-training of personnel, real-time data processing, immediate access to experts. Current remote operations models will continue to evolve by further integrating several classic service deliveries, like directional drilling, measurement and logging-while-drilling (MWD/LWD), mud logging, drilling fluids, wireline logging and other services and job functions. This integration will occur because automated advisory systems will be available, delivering advice based on a wider range of surface and downhole data as well as historical databases and best practices, replacing individual judgment and assumptions. This will significantly contribute to improved HS&E performance as well as risk mitigation. Automated systems in close combination with new cross-trained functions in the operations centers and re-manning of rig sites with reduced POB therefore will become the next step in automation of the overall drilling process.

Since the late 1990s, remote operations centers have focused on infrastructure and remote data gathering as some of the key resources in the intelligent oil field. Data gathering has low direct value unless used to mitigate risk and enhance operational efficiency. Rigsite experts work under the framework of health safety and environment (HS&E) and operational progress, with limited ability to analyze data. There is limited value in data gathering without real-time analysis of the information. This analysis is becoming one of the most important factors of daily work in remote operations centers. Real-time analysis is performed by multi-disciplinary teams, and remedial action can be taken immediately to mitigate risk. This is the strength and force of the operational centers; available interpretation technologies and time to perform the tasks in an environment without the rigsite stress factors. During traditional operations, the wellsite personnel are responsible for the well and for ensuring nothing hazardous occurs, or taking action before or after an unwanted occurrence. In many cases, this is too late. Operations center planning, modeling and analysis – to avoid unwanted situations - are all part of the operational procedure, providing trends and thresholds for procedure change prior to an incident. The wellsite personnel determine indications of well instability with potential to lead to extensive use of resources to ensure stable conditions. This is often based on experience and local knowledge. The onshore team focuses on proactive processes to ensure the overall operational progress is conducted in a safe manner. To illustrate data gathering and risk mitigation of a remote operational center, the BEACON center concept is used to display rigsite workflow, data analysis and feedback for maximum progress and minimum risk. Subsurface knowledge through drilling optimization and BHA reliability will be covered.

The development of remote operational centers has improved data quality due to the increased focus on data acquisition and real-time usage of data. Data quality has different connotations to various participants in the oilfield. Data streaming and continuous flow of data is the main focus for the technical part in delivering and receiving data. Scientists focus on the accuracy of each data point. Most surface sensors measure milliamps with calibrations for accuracy. Reservoir measurements have porosity and permeability as the main reservoir properties, values that are not measured directly and derived from other sources. In automation processes data streaming must be flawless. Through remote operations the surveillance of data streaming quality and accuracy is performed. In most areas the response time on the network is too narrow to stream data from the well to a remote location and to then stream a command or solution back for full closed-loop control. During the acquisition, aggregation, distribution and finally visualization there are room for changes in the data point s. These changes are from uncertainty, stacking, filtration, unpacking, transmission, and any other data handling process for data sharing. For the digital oil field, data are evaluated in two different settings, real-time and after the event. The interpretation is performed either remotely or at the wellsite. There is room for improvement in all areas, depending on objectives in the process: -Automation in the operational phase-Interpretation based on a model update-Automated quality control This paper illustrates the differences and similarities between real-time operations and processes performed on the data later and how combined local and remote operations enhance data quality. We will follow up by making improvement suggestions in all areas moving into the digital oil field.

For anyone involved in organizational changes, people development, optimization of work processes, and reduction in overall risk exposure at the rigsite, the ultimate goal is to develop automation where possible. Automation has been used for years in the car industry, and the oil industry is slowly adopting the potential of automated systems for the drilling environment, gradually integrating all associated processes or important downhole data in full range.Baker Hughes, with strong support from Statoil, has since 1999 developed a remote operations model based on the Baker Expert Advisory Centre/Operations Network /BEACON) platform, starting with remote operations monitoring from an onshore operations centre. Subject matter experts were placed in the operations centre to process the data in real time, leading to significant changes in work processes both on-and offshore. New positions were developed and new shift plans were implemented. As new downhole tools were developed new service levels such as drilling optimization, ECD management and reservoir navigation services were introduced, all remotely from the operations centre requiring no additional personnel at rigsite, all made possible by rig connectivity, data transfer capabilities and proper work process delineation.Tomorrow's solution will integrate all available surface and downhole data, and automated advisory systems will deliver advice based on a wider range of combined real-time data, as well as historical databases and best practice, empowering individual judgment and assumptions. This change will significantly contribute to improved operational performance as well as risk mitigation and reduced Health, safety and Environment (HS&E) exposure.Drilling process automation is something the industry has been anticipating. This paper will discuss the automation potential with respect to remote operations ability, the required development of traditional field positions, collaboration models (e.g., operator/service provider/rig contractor), improved operational efficiency and expectations for operational cost reductions.

The Grane reservoir consists of massive turbidite sand deposits with intercalated shale bodies related to deformation of the reservoir and encasing shales. When drilled, these shales often become unstable after some time, resulting in packoff and collapsed hole, leaving planned produced intervals unrecovered. To maintain oil production from the Grane field, wells are drilled to compensate for declining production. Different strategies to stabilize the shale intervals have been unsuccessful. Real-time geological information collected while drilling are interpreted and used to understand the shape and extension of the unstable shale bodies in the context of the seismic data. This interpretation is based on azimuthal resistivity and gamma as well as extra deep reading resistivity. Using this information, the drilling system is pulled back into the sand section in front of the unstable shale and an openhole sidetrack is performed. Based on the updated interpretation of the geological data gathered while drilling through the shale, the new wellpath is designed to avoid the shale interval and penetrate reservoir intervals farther out. Openhole sidetracking is performed using the main 3D rotary steerable system (RSS) drilling bottomhole assembly (BHA). No cement plugs, ramps or kickoff BHAs are required, resulting in significant time savings. This method is proven on a number of wells and is today a part of standard well-planning on Grane. The applied method is so far the most efficient way to increase the length of the productive intervals and has proven to be a reliable and low-risk operation with a high probability for success. This paper will describe how the combination of real-time geological information and possibilities to perform openhole sidetracks are systematically used to increase the reservoir sections on Grane. Introduction The Grane oil field is located in the Norwegian North Sea, some 200 km northwest of Stavanger (Fig. 1). The field was discovered in 1991 and came on stream in September 2003, and is the first field on the Norwegian continental shelf to produce heavy (19 °API) crude oil. The oil is contained within the Heimdal Formation sands of Paleocene age. Grane has been developed with an integrated accommodation, processing and drilling platform with a fixed steel frame construction resting on the seabed at a water depth of 127 m.