As well construction progressed into increasingly deeper water depths targeting deeper reservoirs, surface casing strings became exposed to additonal risks during various phases of execution and well design requirements. Beginning with handling and installation, they are subjected to handling and environmental loads from various metocean conditions. Once set in place, they see increased exposure to higher well and structural loads while being subjected to deeper hole sections before additional casing strings are set in place. Deepwater casing strings are installed prior to the drilling riser being installed, which creates additional exposure to loads and risks not seen by other casing strings as well as loads induced by the well. To ensure the casing string is fit for duty, a "cradle to grave" approach is utilized to identify and classify the risks created by loads induced on the casing string. Each risk is analyzed and mitigated with a technological solution or best practice to ensure the design parameters of the well are achieved. Introducing advanced mechanized tubular running technologies resulted in up to 20% reduction in exposure of the surface casing string to dangerous seastates and ocean currents and a 41% reduction in red zone entries. Exposure of the surface casing string to environmental loads was further reduced by 7% with the use of an innovative hands-free anti-rotation key, which requires no installation on the rig floor during tubular handling operations and lowers red zone entries beyond current mechanized handling solutions. Once set in place, surface casing strings are subjected to a higher classification of well service as structural and well loads increase in severity. To address this, a new weld-on connector qualified to connection assessment level I+ for gas tight service with elevated temperature per API RP 5C5 / ISO 13679 was installed, allowing deeper wells in deeper waters to be achieved. It is sometimes necessary to temporarily protect the well with deeper hole sections exposed to the surface casing string. Additional challenges to effectively seal the well are present when the string contains internal weld seams and inside diameter restrictions such as the high-pressure wellhead housing and supplemental casing adapters. To overcome these challenges, a unique retrievable packer system was developed and validated to API 11D1 and ISO 14310, allowing well protection from the surface casing string and below.

In the search for attractive hydrocarbon resources, geological targets are often encountered that are designated as high-pressure, high-temperature (HPHT). To ensure an HPHT well meets or exceeds design life, a very thorough design review is needed for all aspects of the well architecture to ensure integrity is maintained throughout. Often overlooked, improper handling and installation through lack of knowledge, equipment selection, or technology have led to many well integrity issues in HPHT wells. The presence of certain corrosive downhole species, combined with the high temperatures and pressures of these wells can accelerate corrosion mechanisms on well bore tubulars at an early stage of the well's life. To address this challenge, corrosion resistant alloy (CRA) tubulars, along with temperature and pressure monitoring equipment, are often designed into the well architecture to ensure well integrity is preserved. These elements must be handled and installed carefully as impressions, marks, and cuts from make-up and handling operations can further accelerate corrosion failures on the tubular, such as stress corrosion cracking, while compromising the integrity of the downhole measuring equipment. To ensure these wells have the best chance of meeting target design life, special consideration should be given to the control line and tubing handling equipment. Specialized equipment, such as control line manipulation systems, offer extra protection to lines as they are manipulated for clamp installation, as well as increased safety and efficiency within the operations. Compensation systems prevent damage to threaded connections during stabbing and make-up while intelligent connection analyzed make-up systems use artificial intelligence and machine learning to provide real-time accurate, consistent, and reliable connection integrity assessments. And lastly, specialized reduced penetration or non-marking technologies can be utilized for make-up and handling of CRA tubulars to minimize or eliminate iron transfer and impressions imparted into the tubular body. By eliminating these, the potential for corrosion cracking due to stress concentrations and other risks of corrosion are also eliminated. One industry sponsored study examined the condition of 406 injection and production wells on the Norwegian shelf. Of these wells, 18% of the wells suffered from well integrity incidents, while nearly 40% of these incidents were due to the tubular string, emphasizing the need for specialized attention and equipment selections for HPHT wells.

It is commonly known that the drilling sector of the oil and gas industry has lagged other batch and process industries such as the automotive and aerospace industries in terms of adopting new technologies. Historically, the oil and gas industry has been risk-adverse to deploying new technologies typically using the mindset "If isn’t broken, do not fix it". Technologies that have made it through commercialization have typically centered around solving a problem or accomplishing something that has not been done before, such as the ability to install heavier tubular strings or the ability to complete a well in an environment not previously accomplishable. However, lower commodity pricing is forcing the industry to become more cost-effective at drilling all types wells such that the industry can remain profitable in the current environment. This has created a technology trend to drill wells at a lower cost, which has put a focus on process improvement and process optimization, something not heavily focused on previously. Borrowing off other industries, an accelerated rate of adopting new technologies is being realized, especially digital and robotic technologies that can remove personnel from the rig floor and automate processes that are repetitive in nature. The drill floor is naturally seen as an area where the repetitious nature of pipe handling, installation, and removal can be automated for safety and efficiency. Although technologies do currently exist to mechanize the process, further automation of the process without compromising the functions required at well center has been difficult to be viewed as value added and profitable. Based on experience and research on these operations, proof of value can be demonstrated to show what makes sense in terms of automating the drill floor.

As the industry recovers from the recent downturn in petroleum commodity prices and the economic impacts from coronavirus (COVID-19), governing authorities in most countries are imposing methodological measures to promote the reduction of carbon footprint. This affects every industry including the petroleum sector. Therefore, most investors and stakeholders have increased their focus on Environmental, Social, and Corporate Governance (ESG) policies. During the well construction phase, a transition from a hydraulic to an electric tong is achieved, resulting in carbon footprint reduction. Achieving carbon neutrality or carbon emission reduction while producing hydrocarbons is one of the topmost key performance indicators (KPIs) in the industry. With the implementation of digital technologies in the tubular and casing connection make-up process, a hydraulic tong is substituted with an electric tong of an equivalent specification. The energy consumption for both systems are calculated and compared. Other important KPIs on tracking operational cost are also assessed and the results are then compared to determine the benefits of implementing the upgraded digitalized tong solution. The electric tong digitalized solution, commercially available in the petroleum industry, is a key enabler for carbon emission reduction while running tubulars in/out of the wellbore. This solution is one of the milestones that serve as foundation to advocate carbon reduction. Eventually, this will lead to establishing carbon neutrality during hydrocarbon extraction and production. The results concluded that a digitalized solution eventually reduced personnel on board working in the "red zone," which eventually leads to carbon emission reductions caused by a decrease in fuel consumption. The decrease of 43% in CO2 emission is observed while performing tubular connection process. Moreover, an overall comparison between a legacy system with the digitalized electric system displayed more than 59% reduction in CO2 during the tubular running services. In addition to carbon reduction, this electric power and control solution allows for more precise torque control, leading to enhanced system integrity and increased reliability achieved by cleaner energy. With this digital solution, not only is the safety and well-being of rig personnel enhanced to avoid any recordable incidents, the reduction of carbon emission is also achieved, aligning to the objectives of current ESG regulatory authorities. This paper will provide comprehensive details on the novelty of this technology and solution offered to the industry.

Until recently the cost of fuel cells for terrestrial applications was prohibitive. Recently, several companies have begun developing high-performance, long-life and cost-effective fuel cell systems, and commercial units are now becoming available for stationary power generation. These systems can often be operated in conjunction with other energy systems to increase overall operational efficiency. A recent technology demonstration project at the University of Louisiana at Lafayette involved the installation, operation and analysis of a fuel cell and a desiccant dehumidification system, which is considered a good combination for the hot, humid climate of the U.S. Gulf coast. The three-year project involved technology assessment, hardware selection and procurement, installation, and operation of the two systems, followed by a performance analysis. The results were reported in a regional symposium. This paper describes the project, focusing on system operation and the results obtained, and predicts future possibilities for integrated energy systems of this type.