With the most recent industry downturn still fresh in many minds, the oil and gas E&P sector is approaching this recovery with a commitment to long-term cost discipline. As a result, augmented reality (AR) and virtual reality (VR) technologies are being adopted by operators and service companies alike as a means of cost savings while driving operational efficiency.
AR technologies employ enhanced visualization hardware, techniques, and methodologies to create new environments wherein digital and physical objects and their data coexist and interact with one another, enhancing the user experience of the real world (
Until recently, these technologies were primarily applied as enhanced entertainment products, most notably within the gaming industry. However, during the past several years, and thanks to the introduction of hands-free, head-mounted display (HMD) technologies, such as Microsoft® HoloLens™ and now HoloLens 2, AR and VR are migrating into the enterprise sector.
While the oil field has not been as quick to integrate AR and VR as other sectors, such as medicine, defense, and aeronautics, operators and service providers alike have increased adoption overthe past 12 months. Motivated by a mandate to keep operating costs low and improve efficiencies in terms of field processes, operators have begun implementing AR/VR applications as collaborative problem-solving, planning, and design tools.
For example, some operators are initiating ARconcepts to promote internal use development and prototyping for both oilfield applications and remote refinery inspections. Additionally, service companies are embracing the use of smart glasses and wearable technologies to help improve remote work and collaboration to help increase in-field safety and reduce downtime.
As part of its strategy to help drive the oil and gas industry's digital transformation, one major service provider is developing AR/VR applications to create digital representations of physical oilfield assets on the Microsoft® HoloLens device. One area of focus is the planning, design, and deployment of solids control, fluid separation, and handling technologies for offshore drilling applications.
In the upstream production systems, the external corrosion management typically does not affect the definition of the whole gathering network system design. However, its role is crucial for the integrity of any steel structure.
The external corrosion is generally managed with external coatings or cathodic protection systems designed to provide a durable protection against corrosive environments (either onshore or offshore). Typical external coating materials are polypropylene, polyethylene (in case of polyolefin coating), fusion bounded epoxy (FBE) or, in specific applications, thermal sprayed aluminium (TSA).
In High Pressure and High Temperature (HP/HT) reservoir applications, usually located in deepwaters offshore where the ambient temperatures are low (i.e. high temperature gradient between inside the pipelines and external environment), the selection of a specific external coating material might have significant impact on the design specification of the installed hardware, with special focus on the pipelines. In fact, depending on different physical properties of the external coating technologies, those may introduce stronger or weaker insulating capabilities and will modify the pipelines U Value, which describes the capacity of the pipelines to exchange heat with the external environment (and consequently the design specification of the production network).
A Case Study is here presented where impacts on the pipeline design specifications based on the selection of different external coating technologies have been described. In particular, it is here shown how the application of coating materials with lower insulating performance, e.g FBE coating, can increase the heat exchange between the hot production fluid and the cold external environment, leading to faster cooldown of production fluid.
In this case, reduction in operating fluid temperature has been used to prevent internal corrosion issues (generally linked to top of the line corrosion), however it may also be used as mitigation of HP/HT related issues, e.g. lateral buckling. Main pros and cons of FBE applied as a standalone external anticorrosion coating have been described in this paper.
Digitalization is the transformation of business models and activities through the strategic use of digital technologies. Despite technological advancements in machine learning (ML), artificial intelligence (AI), and virtual reality (VR), there remains a low maturity of digitalization across the oil and gas industry, especially in offshore operations. There are many roadblocks on the way to digitalization, from data silos to legacy systems. Operational inefficiency is one of the most painful byproducts of these problems.
To complete a single maintenance task, for example, on-site workers may need to access several separate systems to get the required data. They rely on printing out the information they need in order to complete the maintenance activities, and after taking notes on pieces of paper, they have to return to their desktop computer to log the performed tasks.
Not having the data readily accessible contributes to overall inefficiency, and offshore workers often run back and forth while performing maintenance tasks, increasing the hours they spend in challenging conditions.
This paper will outline an application design philosophy for oil and gas companies that combines academic and practical insights, an emphasis on continually testing products in development, and an overall goal of creating value.
This paper will describe how a Nordic software company is using the design philosophy to help an oil and gas operator in Northern Europe optimize on-site operations -- including increasing efficiency and safety -- on its offshore installations on the Norwegian Continental Shelf.
Specifically, the paper will show the software company ingested and contextualized operational data from the operator's assets and made historical data available for field workers via an application for computers and smart devices. This included access to sensor data and historic equipment performance data; all documentation related to maintenance, including procedures, drawings, piping and instrumentation diagrams (P&IDs), and maintenance logs; and interactive 3D models of installations and equipment.
After only three months, the crew at one of the operator's oil installations saw significant increases in the number of monthly maintenance jobs (up to 10% for certain tasks) and reduction of the time spent on certain routine inspections (in some cases up to 50%).
Risk Assessments are used to assess the impact of alternativedesigns, changes during operations, and compliance of offshore installations against tolerabilitycriteria. Typically, asset information is used to develop a mathematical model; this can beupdated to reflect changes during the facility's lifecycle. This paper examines how the use ofcloud-based technology to develop a Digital Twin improves efficiency. Allowing projectstakeholders full access to the QRA model also enables greater understanding of hazards.
Digital technology pervades all areas of business and societyand offers great advantages to safety engineering relative to traditional approaches. This paperdemonstrates how cloud basedtools canturn the traditional static QRA process into a living QRA which can be updated throughout aninstallation's lifecycle by creating a digital twin. This type of living QRA allows projectstakeholders to change key parameters and assess the effect of these changes on risk levels. Inaddition, the results can be interrogated down to fundamental levels using a Microsoft Power BIdashboard.
The output of QRAs are usually static reports providing anoverview of the detailed work undertaken and a high-level summary of the results which arecompared with tolerability criteria or to demonstrate ALARP. This paper demonstrates howcustomised internet browser tools utilising 2D and 3D graphics may be built on top of the QRA toextract more detail than previously possible and communicate risks in a flexible and interactiveway. It also shows how consistent data management can form a basis for innovating beyond thetraditional approach. This allows a wider range of stakeholders to determine risk drivers, isolatesingle accident scenarios and filter results to a greater depth than is possible through a paperreport and allow a greater understanding of their hazards.
Digitalisation is an increasingly ‘hot topic’ in the process industry. Making use of new technologies to provide greater insights can aid in better and more timelyhazard management whilst reducing costs to stakeholders. Examples of innovations which promote better assessment are provided.
Nine years have passed since the Deepwater Horizon disaster and industry is in a considerably better position to respond to a loss of well control of that scale. With the delivery of the Offset Installation Equipment (OIE) in January 2018 the joint industry Subsea Well Response Project (SWRP) has drawn to a close. Despite this, equipment and services continue to be developed. This paper will communicate developments in subsea well response technologies and the latest guidance developed by industry.
This paper provides an overview of the International Oil and Gas Producers (IOGP) Report 594 - Source Control Emergency Response Planning Guide for Subsea Wells. What should a comprehensive subsea Source Control Emergency Response Plan (SCERP) consider? What resources including manpower, expertise and equipment would be required for a controlled response? In addition, it provides an overview of recent enhancements in subsea well response equipment. This includes; offset installation equipment (OIE) for shallow water scenarios where vertical access above a wellhead may not be possible and air-freight capping stack solutions to minimise incident country configuration and testing.
The findings from technical and logistical studies, whilst developing this technology, will be clearly communicated for industry consideration. This includes critical activities to be considered in developing response times models. This paper will demonstrate that capping equipment located in country does not necessarily improve the overall response time for a loss of well control event; an effectively planned response is more important than immediate hardware availability. The importance of mutual aid of personnel and equipment in a response will be key as not one company can provide all the solutions.
Although only required for remote or land locked basins, to further enhance industries capabilities, it has recently been demonstrated that existing ram based capping stacks can be transported by air, without disassembly, and thereby maintaining pressure boundaries. This allows for a more rapid air mobilisation to the incident location without the need for major re-assembly upon arrival.
As a result of the 2016 Paris agreement, the challenge of climate change and the imperative of moving to a low carbon economy has intensified. This challenge has been added to the traditional objectives of affordable and secure energy sources. These three criteria are the basis for the Energy Transition. Increasingly, investors, consumers and policy makers are looking to energy businesses to reflect all these criteria as the basis of their company culture and objectives.
This paper looks to explore opportunities for the UK oil and gas industry to further align itself with the drivers set out above and continue to promote investment into a sector that is key to delivering the Energy Transition:
Improved communication of carbon reduction and mitigation efforts at both a national and global level Increased collaborative efforts aimed at reducing emissions resulting from exploration and production offshore The potential for UKCS oil & gas companies’ involvement in carbon mitigation and storage
Improved communication of carbon reduction and mitigation efforts at both a national and global level
Increased collaborative efforts aimed at reducing emissions resulting from exploration and production offshore
The potential for UKCS oil & gas companies’ involvement in carbon mitigation and storage
Over recent years, the offshore UKCS oil and gas sector has focused on improving cost efficiency in its offshore operations. This implies a commitment to continuously improve environmental performance despite the challenges of doing so in a maturing oil and gas basin, where maximising economic recovery from fields requires greater effort. Notwithstanding these challenges, the overall long-term trends in environmental performance are improving as a result of efforts by the industry.
Moving forwards, the benefits of effective emissions management will continue to intensify, beyond the regulatory requirements of environmental protection, as a result of two key drivers:
To maintain investor and public confidence – reducing both the carbon footprint of operations and carbon intensity of products used by consumers, will help position companies for a lower carbon economy. The business case - EU ETS Phase IV is modelled to cost the sector £2.2 billion from 2021 to 2030 as the cost of allowances is projected to increase combined with the reduction in free allowances. Therefore, reducing emissions at installations will continue to be imperative for improved environment performance as well as the continued economic viability of the installation.
To maintain investor and public confidence – reducing both the carbon footprint of operations and carbon intensity of products used by consumers, will help position companies for a lower carbon economy.
The business case - EU ETS Phase IV is modelled to cost the sector £2.2 billion from 2021 to 2030 as the cost of allowances is projected to increase combined with the reduction in free allowances. Therefore, reducing emissions at installations will continue to be imperative for improved environment performance as well as the continued economic viability of the installation.
The sector must therefore continue to adapt to these ongoing fundamental changes that are taking place in energy supply more widely. As with any industry, businesses need to respond to shifting economic and societal demands and the consequent changes in energy needs. Hence, the effective management of emissions must proliferate through both operations (exploration, production and transportation of hydrocarbons), and use of the products delivered.
It is often stated that necessity is the mother of invention. Never is this proverb more relevant than in the offshore oil and gas environment we currently operate in where real step changes leading to reduced capital and operational expenditure opportunities are sought and embraced by field operators. This paper discusses the pre-job planning, field execution and lessons learned from one such technology that challenged conventional thinking of sand faced completion, casedhole completion and well integrity to successfully deliver a single-trip, interventionless, sand control completion in deepwater Bonga Field, located on the continental slope of the Niger Delta.
Convention dictates that the vast majority of offshore completions be run in two and sometimes three trips which routinely takes in excess of eight to ten days to deploy. Given the day rate of high specification rigs capable of drilling in deep water environments, the ability to reduce this time was deemed paramount to the economics of the project. Utilizing a collaborative approach to initial concept design, risk assessment, extensive testing and contingency planning at component and system level, a single-trip, interventionless, sand control completion system was designed and successfully installed. This paper describes the completion architecture, operational sequence and challenges leading to the installation of an interventionless completion.
A clearly defined set of deliverables and design principles were drawn up to guide the direction of the project including: successfully deploying the upper and lower completion in one trip, and testing all barriers. Adopting a simple, low risk and high reward design, meeting clients well barrier requirements and utilizing proven cost-effective technology are examples of design principles used. The system was tested and evolved through a number of iterations in an onshore trial well environment on a number of occasions leading to the first successful deployment completed in the second half of 2018, resulting in an average completion installation time of 5 days, versus the average 10 days for deploying multi-trip completions. Details of the successful installations, lessons learned, along with planned future activity are outlined within the body of this paper. While several of the components incorporated in the single-trip system had been run previously in isolation, this paper also discusses the steps taken to facilitate the first full-system approach to the application of radio frequency identification (RFID) enabled tools in the first single-trip, interventionless sand control completion system. Several components within the completion have been equipped with this technology including a multi-cycle ball valve, wire wrapped screens fitted with inflow control device (ICD), remote operated sliding sleeve for annular fluid displacement.
Lee Allford (Energy Institute) It is estimated that more than 120 platforms with a combined weight of more than 1 million tonnes will be decommissioned over the next 10 years in the North Sea alone. This will involve a significant number of personnel engaged offshore in potentially hazardous operations during the removal of these facilities, underlining the need for ensuring high standards of process safety within the associated decommissioning projects. The need for effective management of process safety during decommissioning was highlighted in the major structural collapse incident at the Didcot power station in the UK in 2016 that resulted in 4 fatalities. This together with the fact that the police and HSE are conducting a joint investigation to consider corporate manslaughter, gross negligence manslaughter and health and safety offences, highlights the gravity of getting it wrong. With support from the Energy Institute and cross-industry involvement from oil companies, contracting companies and the UK Safety Regulator, new guidance has been developed that will support those engaged in decommissioning offshore facilities to plan, design and execute their projects so as to manage risk from major accident hazards (Energy Institute, 2019). This paper presents the key elements of this guidance which provides a roadmap to managing process safety across the lifecycle of a decommissioning project, from initiation through execution. The guidance is set-out according to typical phases of a decommissioning project, providing useful insights into key process safety considerations, objectives, tasks and outputs.
The field startup is Hurricane’s first step to actualizing its potentially considerable resources in the UK North Sea. Lancaster is expected to produce an average of 17,000 BOPD by the end of the year. Logistical work is taking place in advance of subsea installation activities, which have the large UK North Sea field on track for first oil in 2019.
Logistical work is taking place in advance of subsea installation activities, which have the large UK North Sea field on track for first oil in 2019. After severe damage in a typhoon, the Huizhou oil field in the South China Sea was back on production in 5.5 months. This paper reviews how this feat was accomplished.