Oil and gas industry interest is surging in using remote survey technologies for more cost-efficient, safer, and lower-carbon certification, verification, and inspection of assets and operations. Amid COVID-19 travel restrictions in 2020, DNV GL has conducted more than 4,000 remote surveys for the sector. These have provided the supply chain with the assurance it needs to keep projects and operations running safely and on schedule. Remote surveys involve fixed and mobile cameras (e.g., smartphones) giving customers instant access to DNV GL experts worldwide for verification, classification, and certification of assets, verification of materials and components, inspection, and marine assurance. The growing track record for remote survey technology could soon make it the method of choice for inspections in some places and circumstances, according to a senior expert at one leading oil and gas exploration and production company.

Often located hundreds of miles away from land, offshore oil and gas platforms pose challenges with their unsheltered maritime environment, heavy weather, and risk of explosive, toxic, and corrosive atmospheres--with limited resources. Sounds like conditions are ripe for robots on rigs. In 14 years at Equinor, robotics researcher Anders Røyrøy has explored the application of robots in jobs that he describes as "dangerous, dirty, distant, or dull," where use of a robot can serve to mitigate or eliminate safety risks for humans. One of the highest priorities for robotic development and deployment, in view of their impact on inspection and maintenance routines, are remote operators for onshore and offshore platforms. Failures in such harsh environments could jeopardize the lives of human operators, the environment, and process equipment.

The offshore oil and gas sector has over the decades come to be defined by megaprojects with 30-to-40-year project horizons. But the future of offshore development will depend on the industry's ability to find innovative ways to cut costs and slim the capital requirements. Many examples were to be shared with oil and gas professionals at the 2020 Offshore Technology Conference (OTC) in Houston. However, due to the COVID‑19 pandemic, this year marked the first time that OTC was cancelled since its inauguration in 1969. Despite the global disruption, the flow of ideas continues.

The offshore oil and gas sector has over the decades come to be defined by megaprojects with 30-to-40-year project horizons. But the future of offshore development will depend on the industry's ability to find innovative ways to cut costs and slim the capital requirements. Many examples were to be shared with oil and gas professionals at the 2020 Offshore Technology Conference (OTC) in Houston. However, due to the COVID‑19 pandemic, this year marked the first time that OTC was cancelled since its inauguration in 1969. Despite the global disruption, the flow of ideas continues.

In a new report, the UK Oil & Gas Authority (OGA) highlights that the country's offshore sector improved its production efficiency for the seventh straight year. In 2012, fixed-leg platforms and floating facilities in the UK continental shelf operated with a production efficiency rate of only 60%. In 2019, the figure jumped by 5% year-over-year to hit 80%--a target the OGA hoped would be reached by 2022. Based on best practice guidelines established in partnership with the SPE, the OGA calculates production efficiency by comparing actual wellhead production vs. the maximum economic production potentials. Production losses include reservoir degradation, plant shutdowns, and pipeline constraints.

For my fourth column on emerging oil and gas frontier regions, I want to focus on the area surrounding the Caspian Sea, the world's largest inland water body and one of the oldest oil-producing regions. So how does this area qualify as "emerging"? First, only in recent years have significant volumes of Caspian oil begun to reach world export markets. Second, the Caspian region is rapidly emerging as an important new source of natural gas. Third, the region's--if not the globe's--most publicized, most prolific oil and gas project, Kashagan, entered Phase 1 of production just a few months ago, after being discovered in 2000.

There are considerable benefits to conducting rigless subsea well intervention from specialized monohull vessels. Two case studies provide an overview of operations on subsea wells, from intervening through the production tree (XT) to XT change-out and well-plug-and-abandonment (P&A)/wellhead-removal operations. Rigless and RLWI activities have been carried out for more than 25 years across the North Sea. The purpose of the following case studies is to demonstrate that with effective project management (planning, developing, execution, and close-out), the use of RLWI is a flexible and extremely cost-effective method that operators can use for a single well or across a number (a campaign) of subsea wells, irrespective of subsea-tree type or close proximity. The SIL provides access to the wellbore.

As the oil and gas industry pushes into deeper water, more-complex environments, and frontier unproduced areas, the technical and nontechnical risks related to appraisal and development of deepwater projects are likely to continue to increase substantially. While the technical challenges related to deepwater developments are significant--perhaps more significant and critical to the venture success--it is important that the nontechnical aspects of managing a new development in a frontier area be incorporated at the onset. After the successful discoveries in deepwater basins across the globe in west Africa, the North Sea, the Gulf of Mexico, Brazil, and elsewhere, operators are using the lessons learned and technologies developed in these fields to explore other frontier deepwater fields. The exploration in deep water becomes complex on the basis of various factors, such as water depth, geological formations, weather conditions, lack of oilfield infrastructure, and material and tools availability. The definition of deep water may vary with operators, but one definition of a deepwater field is any area of exploration where the water depth is greater than 150 m and there is a subsea blowout preventer.

Over the last 40 years, the Campos Basin has been a major stage for technology development to push offshore oil and gas production to water depths (WDs) never before experienced. This paper presents a retrospective of the most-significant technologies developed and deployed in the Campos Basin for more than 80 production systems in more than 30 oil- and gas-field developments; a few of these milestones are described in this synopsis. The discovery of oil in the Campos Basin in 1974 occurred in the context of the 1973 world oil crisis and its effects on geopolitics and the global economy. In addition to the challenges associated with this period, a need existed to increase oil production while reducing costs, leading to a fast-track approach. The development of the Garoupa field, followed by the Pargo, Badejo, Namorado, Enchova, Bonito, and Pampo fields, revealed huge oil-production potential, minimizing Brazil's need to import petroleum.

An application at the forefront of the accelerating digitalization of offshore exploration and production (E&P) is remote condition monitoring (CM) of platform equipment, especially with a unique data-sampling technique called time stamping. CM tracks the performance data of equipment, watching for deviations from baseline performance benchmarks. Any unexpected variances from those established baselines may indicate a developing fault in systems found typically on offshore platforms. Technicians can then be dispatched to further investigate or service the equipment, targeting root causes of the variances--an approach called condition-based maintenance (CBM). The CBM approach has shown that it can improve reliability, availability, and asset use.