Drilling companies are constantly evaluating ways to improve the efficiency and safety of their operations, the way the returns of the well are circulated while drilling has remained unchanged for decades, however, having a circulating system open to the atmosphere imposes a risk to the drilling crew in the rig flow. Conventional influx detection methods can easily allow the gasification of the mud column in the annulus before it is noticeable and H2S or flammable gas alarm can be triggered before any action is taken. A rotating control device (RCD) is a piece of equipment that diverts the returns of the well from the rig floor while allowing the drill pipe to be rotated and reciprocated, that means tripping and drilling operations can be performed while the well is isolated from the rig floor by the RCD. The RCD is a key component in Managed Pressure Drilling (MPD) operations as it is responsible for containing the annular surface pressure and preserving the integrity of the circulation system, hence maintaining a slight overbalance condition on the well, additionally the RCD can be deployed independently for other applications that enhance the safety and optimize the costs of the drilling operation. For this reason, efforts are made to ensure that optimum operating conditions are present to reduce the chances of system failure. Historical data detailing the performance of RCD systems, including total stripped footage, total rotating hours and failure mechanisms were used to evaluate the reliability of this technology and to set operating limits to optimize its performance. Historically there are conditions that are known to reduce the life span of RCD bearing assemblies, such as misalignment of the Blowout Preventer (BOP) stack, hard banding or bad condition of drill pipe tool joints, excessive drill pipe vibration, temperature and type of fluid out of the well, among others. Ensuring that the operating limits are observed regarding rotating speed, pressure and temperature were observed to be key to maximizing the life cycle. It was observed that the base technology over which RCDs are designed is far from recent and new additions to the current setup are needed to "smarten up" an otherwise very basic piece of equipment, this with the intention of obtain better data regarding its operating conditions and the parameters that affect its performance. New technologies in terms of elastomer compounds, seal design improvements, monitoring systems and implementation of artificial intelligence are some of the upcoming developments discussed in this document and that are to be implemented in the short and medium term in RCD operations in Kingdom of Saudi Arabia.

Managed pressure drilling (MPD), which has been heavily refined and readily practiced in offshore and deepwater operations, could open many doors to untapped potential on land—a concept often underestimated. Operators look to MPD technologies—for example, multiphase MPD or drilling gas—to access challenging or partially depleted wells when the conventional approach has failed or is economically unfeasible. One critical technology component that enables drilling with gas is the rotating control device (RCD), a pressurized secondary well control barrier that contains and diverts flow at surface. Coupled with an MPD system (choke, coriolis meter, etc.), the RCD enables early kick detection and the ability to manage the annular hydrostatic pressure profile using surface backpressure. Adding to the well control benefits realized by the RCD is its sealing capabilities. Weatherford conducted nitrogen gas testing of RCD elements in accordance with API 16RCD testing criteria—the industry's first testing of RCDs for gas-tight sealing. Pressure control, MPD-enablement, and gas-tight sealing are the perfect combination of RCD capabilities that will enable new techniques for drilling optimization in depleted reservoir sections. This paper will detail the inherent challenges of RCD gas-tight sealing and shed light on the significance that proven testing could deliver to the market for empowering new techniques that could lead to an unforeseeable number of drilling triumphs in the near future.

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.

Digital transformation is a term that continues to be popular with the oil and gas industry. The industry's historic opposition to the adoption of innovative technology seems to be fading as operators, contractors, and service providers alike continue to invest in innovative solutions around not only digital technologies, but also in process and system optimization techniques. However, while operators are more willing to adopt newer and automated technologies, the "proof of value" burden still falls on service companies. Perceived value to operators may vary slightly, but overall, the industry has focused on two core tenants of value: Increased safety and efficiencyPersonnel reduction For widespread adoption of an enhanced digital solution, the technology must not only provide quantifiable value in at least one of the core tenants, but also must repeatably demonstrate the value in the field. The case study presented demonstrates the value added by introducing a new proprietary Programmable Logic Controller (PLC) based solution into the tubular running process. This system allows for tong operation, elevator and slip function, and single joint elevator (SJE) operation to be performed by a single person, rather than three or four personnel crew, as traditionally employed during tubular running operations. All functions are intelligently executed from a triple certified hazardous zone rated wireless tablet by a single operator's command while located inside the driller's cabin. Through the deployment of a new consolidated and intelligent control system, the rig was able to reduce the number of personnel typically required for casing run and rack back operations down to two operators per tower, which equates to as much as a 66% reduction in personnel needed for tubular running operations. Additionally, the system allowed the operator to control the equipment from inside the driller's cabin, which improved communications and reduced red zone exposure by 30% while increasing run time efficiency by as much as 11% on some connection strings.

Important key performance indicators of offshore well integrity management include mitigating drilling hazards without inducing others and maintaining control of the well in the process. Offshore applications of Managed Pressure Drilling (MPD) tools and technology have been steadily increasing over the past decade primarily for these reasons. Its growing acceptance has been influenced by drilling prospects deemed to be un-drillable with conventional circulating fluids systems for safety, economic, and/or technical reasons, increasing recoverable reserves in the process. MPD's pristine onshore well control track record is now being recognized as a safer way to drill a growing number of offshore prospects that could not be drilled with a conventional open-to-atmosphere mud returns system 4 .There are four variants of MPD practiced offshore; Constant Bottomhole Pressure (CBHP), Pressurized Mud Cap Drilling (PMCD), Returns Flow Control (RFC-HSE), and Dual Gradient Drilling (DGD). CBHP for drilling in narrow, shifting or relatively unknown safe mud weight windows, PMCD for drilling in severe to total loss zones, RFC-HSE to augment safety systems and methods when drilling with an otherwise conventional fluids program, and DGD for reducing equivalent mud weight (EMW) when drilling depleted formations from shallow water rigs and eliminating gross overbalanced conditions when drilling from deepwater rigs 8 .Over the past decade, key enabling tools have been developed to enable the safe and effective practice of MPD on all types of offshore rigs and water depths; marine series rotating control devices, MPD automated control systems, MPD hydraulic flow modeling, MPD well control matrix, etc. Early kick and loss detection is a flagship capability, as well as ability to conduct formation integrity and leak-off tests more frequently than industry norm by doing so while drilling, quantify and virtually eliminate ballooning 3 , closed-loop cementing, and managed pressure wellbore strengthening, all of which represent state-of-the-art well integrity management capabilities.Whether it be in shallow water, deepwater, or ultra-deepwater, a growing number of otherwise promising prospects are deemed un-drillable with conventional circulating fluids systems. The industry has already drilled the majority of the available 'easy' wells with drilling hydraulics whose root principals were developed over a century ago. MPD is poised to become the next 'conventional' way to drill in marine environments within the next decade. This presentation will illustrate to the offshore drilling industry, regulatory and stakeholders why that is expected to be the case.