Search Results

We are pleased to welcome Jonathan Clark as our new Advisory Consultant for the Gulf of Mexico and North America markets! With over 20 years of expertise in subsea technology and market development, Jonathan brings a strong track record of product innovation and strategic growth. His leadership and industry insight will be invaluable as Neodrill expands its presence and delivers innovative subsea solutions to meet the needs of this critical region. Welcome aboard, Jonathan!

This summary is based on the paper "Case Study: First Deployment of a Subsea Well Foundation by Jack-up Rig with Surface Wellhead,"  presented by J. Young, D. Gourlay, G. Mathieson (TotalEnergies E&P UK Ltd), and W. Mathis, J. Alsvik (NeoDrill AS) at the SPE Offshore Europe Conference and Exhibition. The full paper can be accessed through the Society of Petroleum Engineers . Essential Highlights First-of-its-Kind Deployment : The Conductor Anchor Node (CAN) technology was used for the first time with a Heavy Duty Jack-Up (HDJU) rig and a surface wellhead in the high-pressure, high-temperature (HPHT) Isabella Appraisal well in the UK Central North Sea. Previously, CAN installations were only done with subsea wells using floating rigs. Challenges and Solutions : The well's location featured interbedded sandy and silty seabed, raising risks for conductor instability and cementing issues. The CAN was chosen to improve conductor stability and reduce wellhead movement, addressing past issues seen in nearby offset wells. Installation Method : The CAN was deployed using the HDJU rig itself, eliminating the need for a separate construction vessel and reducing project costs. The rig's drawworks were used to lower the CAN, and a remotely operated vehicle (ROV) applied suction for seabed penetration. The system ensured the CAN remained stable and within acceptable inclination limits during installation. Operational Results : The installation was successful, achieving targeted penetration and inclination while preventing conductor movement. The technology improved fatigue life by securing the conductor at the seabed, allowing drilling without further stability issues. Recovery operations were performed with a Construction Support Vessel (CSV) for economic reasons, with the CAN showing minimal wear and readiness for reuse. Conclusion and Future Implications : The case study demonstrated the feasibility of using CAN technology with HDJU rigs for challenging conditions, showing potential for significant cost and time savings. Future projects should consider factors like weather, soil conditions, and rig capabilities for similar deployments. Abstract This case study highlights the first-ever deployment of a Conductor Anchor Node (CAN®) well foundation with a surface wellhead on the HPHT Isabella Appraisal well in the UK Central North Sea, using a heavy-duty jack-up rig. Unlike previous applications with floating rigs, this installation was carried out with the jack-up rig on-site, reducing costs and risks. The foundation was installed offline during pre-spud operations, using a drillstring and ROV to apply suction for precise placement. The technology provided structural support, improved fatigue life, and enhanced cementing quality, addressing key challenges in shallow formations. Introduction In the UK Central North Sea, HPHT wells using a heavy-duty jack-up rig with a surface wellhead face challenges with conductor instability due to difficulties in achieving proper cementing at the mudline, especially under extreme pressure and temperature conditions. Traditional solutions relied on costly remedial cementing, but for a recent HPHT well in sandy seabed conditions, a suction anchor well foundation was introduced to proactively address this issue. This marked the first use of the technology with a surface wellhead and HDJU rig in such conditions. The paper details the engineering design, installation method, and results of this novel application, highlighting its potential for future use. Challenges Associated with Well Surface Location During the planning of the HPHT appraisal well, the proximity to a shallow Coal Pit channel with silty clay and sand presented a high risk for conductor instability and cementing issues. Offset reviews revealed similar wells in the area experienced significant problems, including conductor movement, failed cement jobs, and wellhead instability. In particular, the nearby Isabella Exploration well faced conductor movement after cementing, adding complexity and risks to operations. Given the potential for winter operations, a long well duration, and the importance of a stable conductor for the well's design, it was decided to use the well foundation technology to proactively mitigate these risks and ensure a competent foundation. Solution identified: Well Foundation The well foundation technology, introduced in 2006, was identified as the solution to reduce tophole delivery risks for the HPHT appraisal well. Consisting of key components such as a skirt section, top lid, guide pipe, and landing shoulder, the well foundation provides a stable foundation by increasing the surface area interacting with the surrounding soil, mitigating conductor instability risks. Additional aids like a water injection system and Integrated Measurement Stab (IMS) were added to address the sandy seabed conditions and ensure successful penetration. A geotechnical study confirmed the feasibility and load capacity of the suction anchor, ensuring it could support the well’s casing strings even in the case of a failed cement job. The foundation’s design reduces wellhead movement, improves fatigue life, and centralizes the conductor while the cement slurry sets, minimizing risks of poor cement bonds caused by conductor movement during standalone operations. The foundation also provides sufficient axial load capacity, ensuring stability in the event of cementing issues. Installation Concept Selection After selecting the well foundation technology, the next step was determining the installation method. Traditionally, well foundations were installed by a dedicated vessel with a crane and ROV, but this had only been done on subsea wells drilled by floating rigs. For the HDJU, the team identified risks with the conventional method, including potential misalignment between the rig and foundation and seabed disturbance from the rig's spud cans. A new approach was proposed: installing the foundation using the rig itself, eliminating the need for a support vessel and minimizing misalignment risks. A detailed study was conducted to assess the feasibility of this rig installation concept and compare it to vessel-based methods. Rig Installation Feasibility The feasibility study for installing the well foundation using the rig rather than a vessel identified several key considerations. First, the unit had to be picked up from a vessel beneath the moonpool, with a shipping frame and shock absorber mitigating the risk of collision. Second, ensuring verticality during suction was critical, with rig skidding adjustments offering limited but sufficient control. Third, the well foundation had to remain central under the rotary table, with drillpipe and slack tide used to ensure positioning. Finally, a contingency for re-spudding was confirmed within the rig’s skidding envelope. After confirming feasibility, the rig installation was selected for further evaluation. Comparison of “Rig Versus Vessel” Installation Options The comparison between rig and vessel installation methods for the well foundation highlighted key risks and benefits. Vessel installation offers flexibility, allowing the well foundation to be installed before the rig’s arrival and timed for optimal weather conditions, but poses challenges with rig positioning accuracy and potential seabed disturbance due to the rig’s spud cans. This could lead to the well foundation becoming unusable if the rig shifts or disturbs the seabed. In contrast, rig installation offers significant cost savings by eliminating the need for a construction vessel and allows for concurrent drilling preparations. However, it carries risks such as weather delays, equipment failure, or alignment issues during installation. Weather analyses showed a low likelihood of delays, and it was concluded that rig installation presented fewer overall risks and higher economic benefits, making it the preferred method. Installation Planning As mentioned above, it was decided to use the jack-up rig to install the well foundation. Since this was the first time this installation method was to be applied in the industry, a meticulous planning and risk analysis process was executed based around the main steps listed below: Load-out to PSV (Platform Supply Vessel) Transit from manufacturing yard to rig Hand-over from PSV to rig Installation by rig Load-out and transit The well foundation was loaded onto a PSV using a tandem lift with two cranes for cost efficiency. It was secured in a specialized sea-fastening frame, which distributed the load, prevented movement during transit, and guided the lift-off operation. Due to the PSV's limited deck capacity and the need for precise positioning near the jack-up rig, a grillage structure was welded to the deck to support the well foundation, which was then secured with chains for easy disconnection and contingency planning. Hand-over from PSV to rig The most critical part of the installation process involves precise coordination between the PSV and the rig to successfully lift the well foundation. Key considerations include exact elevations, position of the PSV relative to the drillstring, and allowable weather conditions. The rigging setup used a 125 mT shackle and 20m pennant to connect the drillstring to the well foundation. Vessel heave was accounted for to avoid re-impact after lift-off. Calculations determined the allowable wave height (Hs) for different lift speeds, and a shock absorber was added to reduce dynamic loads, allowing safe lift-off at a 3.5m Hs. A detailed simulation was used for training and visualization of this complex operation. Installation by jack-up rig The installation of the well foundation by a heavy-duty jack-up rig (HDJU) follows a similar process to installation by a construction support vessel (CSV), but with key considerations due to the limited skidding window of the HDJU. A detailed analysis ensured the rig could align properly above the well foundation, allowing for some vertical misalignment between the conductor and guide pipe. The inclination limit was increased from 1.0 to 2.0 degrees to accommodate the HDJU's alignment, while still allowing conductor installation within 1.0 degree. ROV access was optimized by adjusting the heading of the suction funnel interface. Results / Operational Execution Installation of well foundation Hand-over from PSV to rig The key steps for the well foundation installation involved ensuring the PSV avoided collision with the jack-up rig by using a deflector tied to the PSV’s positioning system. The rig crew prepared the lifting string and performed a dry run to ensure smooth operation. Communication between the drawworks operator, PSV bridge, and installation supervisor was critical. Favorable weather conditions allowed for a lift-off speed of 0.4 m/s without needing a shock absorber. The operation proceeded smoothly, with flawless space-out of the drillstring and stable load transfer from the PSV to the rig. Deployment and self-weight penetration During deployment, additional drillstring stands were made to lower the suction anchor to the seabed without needing mid-operation connections. The operation paused at 6 meters above the seabed to wait for slack tide, preventing misalignment. Self-weight penetration was performed in 5 mT steps, reaching 0.6 m penetration with an inclination of 1.2 degrees, within the required 2.0-degree limit. The ROV confirmed alignment, and the operation proceeded smoothly. Suction phase After completing self-weight penetration, suction was applied to further drive the suction anchor into the seabed, creating a downward force and fluidizing the sand at the skirt's tip to ease penetration. The inclination reached the upper limit of 2.0 degrees, so the rig was skidded to apply a horizontal force, which gradually reduced the inclination. The final results showed a penetration of 6.2 meters (target 6.0 meters), an inclination of 1.3 degrees (within the target of 2.2 degrees), and an orientation of 330 degrees (target 303 degrees). Despite limited visibility, the disconnection of the lifting slings was smooth, and the rigging was successfully recovered without any issues. The water injection system was not required, as the necessary penetration was achieved without it. Final operations After the well foundation was installed, the guide pipe lid was detached and recovered to the surface. The ROV then sealed the water injection valve with a blind plug and opened the cuttings and cement removal system valves for drilling operations. Finally, blind plugs were installed on the pressure measurement and IMS stab receptacles to complete the preparation. Drilling operations Drilling operations began with the 36 in. tophole section drilled through the well foundation guide pipe, and cuttings were effectively removed by the ROV applying suction. The 30 in. conductor was run and cemented, with the removal system clearing cement slurry without buildup. No conductor or wellhead movement was observed during the well, and no additional cement job was needed. For well abandonment, the conductor was cut at the base and top of the well foundation, with the top cut allowing for recovery. Minimal cement between the conductor and the foundation confirmed the unit’s stability without cement reinforcement. Recovery operations The well foundation recovery was carried out by a CSV instead of the rig, as recovery would have been an online operation, incurring additional rig and drilling costs. Using a vessel was more economical, especially since rig operations ended in January when weather conditions were not ideal for landing the foundation onto a vessel. The recovery process was standard and is summarized briefly below. Installation of guide pipe lid The recovery operation followed the reverse order of the installation, starting with the guide pipe lid. It was lowered and secured with four locking screws under ROV assistance. Although a backup bolt pattern was available in case of damage or blockage from cuttings or cement, the main pattern was used without issues. Pump-out phase Due to weather delays, the pump-out began before the lifting rigging was attached, lowering the well foundation by 1.2 m. Pumping was paused after the inclination reached 2.0 degrees. Once conditions improved, the rigging was connected, but further movement stopped, indicating water breakthrough (piping) had occurred, preventing pressure build-up. Lift-out Phase The ROV monitored the lift-out of the well foundation as tension was gradually increased, achieving a controlled lift-out. Early piping was expected, and the vessel's capacity allowed for up to 170 mT pulling. The well foundation was safely landed on deck, with precautions in place to avoid dropped objects. After transit, all equipment was demobilized, and the well foundation was successfully prepared for reuse. Conclusions This case study demonstrates the successful use of a suction anchor well foundation with a HDJU rig and surface wellhead, enhancing conductor stability in challenging seabed conditions, especially in soft sands. The system improved fatigue life and reduced movement, which is crucial for standalone HPHT wells. Additionally, the study shows that the well foundation can be installed using the rig itself, though factors such as weather, rig specifications, soil conditions, and boulders need careful consideration. If done offline, this approach can significantly reduce project timelines and costs. For more detailed insights, the full paper can be accessed through the Society of Petroleum Engineers . Acknowledgements The authors wish to acknowledge the support provided by TotalEnergies’ partners in the Isabella joint venture: Neptune Energy, Ithaca Energy and Energean. Particular thanks are also given to Darren Richardson and the Shelf Fortress team from Shelf Drilling for their significant contribution to the safe and efficient delivery of this project. References Young, J., Gourlay, D., Mathieson, G., Mathis, W., & Alsvik, J. 2023. Case Study: First Deployment of a Subsea Well Foundation by Jack-up Rig with Surface Wellhead.  Presented at the SPE Offshore Europe Conference and Exhibition, Aberdeen, UK, 5–8 September. SPE-215583-MS. Society of Petroleum Engineers.

This summary is based on the paper "Smart Well Foundation, the Cost Efficient and Environmental Choice for Field Developments,"  presented by Camilo Cardenas, Hans Erik Kolstrup Hansen, Sigvald Hanssen, Harald Blikra (Repsol Norge AS), Wolfgang Mathis, and Ole Kristian Holen (NeoDrill AS) at the SPE/IADC International Drilling Conference and Exhibition, 2021. The full paper can be accessed through the Society of Petroleum Engineers . Essential Highlights CAN Technology Overview : The Conductor Anchor Node (CAN) serves as a smart well foundation for rig-less conductor installation, integrating the conductor, manifold, and tie-in points, enabling early production and reducing project timelines. The technology has evolved from simple conductor installation to the CAN-integrator, which supports wellhead systems and Subsea Production System (SPS) equipment. Operational and Cost Benefits : Installing the well foundation before the rig arrives saves 2-4 rig days, with verified conductor load capacity in advance. The approach reduces top-hole construction costs by 21-44%, equivalent to significant CO2 emission reductions (400-600 metric tons per well). The well foundation’s smaller footprint and lighter weight compared to conventional structures simplify marine operations, reducing downtime and installation costs. Environmental and Safety Advantages : The CAN-integrator minimizes environmental impact, with lower emissions across multiple categories, including climate change and human toxicity. By enabling operations with smaller vessels and fewer campaigns, it contributes to reduced environmental footprint and improved safety. Flexibility and Integration : The technology supports various levels of integration, from standalone well foundations to more complex systems with flow bases and trawl protection. It facilitates flexible field development strategies, allowing for phased expansions and easy adaptation to changing project requirements. Accelerated Time to Production : The CAN-integrator allows for early installation of flowlines and other infrastructure, decoupling drilling from flowline installation schedules and enabling quicker production start-up. Abstract The CAN® (Conductor Anchor Node) technology streamlines subsea satellite well production by integrating the well foundation, manifold, pipeline, and umbilical tie-in points, allowing for faster production start-up. By installing the well foundation with smaller marine vessels before the rig arrives, it reduces time delays and eliminates the need for large-scale drilling and cementing operations. This approach enhances efficiency, cuts costs, minimizes operational risks, and significantly reduces the CO2 footprint by 21-44%, or 400-600 metric tons. Field-Proven Building Blocks The presented strategy leverages existing, field-proven technologies by combining them in a more efficient way, using the well foundation for multiple purposes throughout different stages of the well lifecycle. The approach takes a holistic view of drilling, completion, and installation, integrating activities across the value chain and contract packages, such as drilling and SPS equipment, to optimize performance and cost-efficiency. Well Foundation Technology The well foundation technology, based on a suction anchor system, allows for rig-less conductor installation and has been successfully used in over 40 projects since 2006. Originally known as CAN-basic, it has evolved into the CAN-ductor, which integrates the first conductor joint and low-pressure wellhead housing (LPWHH) onshore. This method offers precise control over cement quality and is ideal for wells with shallow top reservoirs, enabling horizontal drilling in challenging conditions. The technology has demonstrated significant rig time savings and has been adapted for various seabed types, including sand and mixed layers. Life Cycle Analysis (LCA) has shown additional environmental benefits in its use. SPS Equipment The SPS (Subsea Production System) equipment, like the well foundation technology, is based on existing proven product lines, requiring only minor mechanical adjustments. The integration of SPS components, such as flow bases and protection structures, onto the well foundation occurs at the manufacturing yard before mobilization, reducing operational complexity. In 2021, pre-installed Permanent Guide Bases (PGB) were successfully deployed in the West of Shetland field development, moving processes from the rig to the onshore yard, resulting in cost, environmental, and operational efficiencies. Further integration of SPS equipment onto the well foundation is planned for future phases. CAN-integrator Definition The well foundation technology bridges the gap between drilling and subsea facilities by providing a common platform for both wellhead systems and SPS equipment. This integration allows for synergies that optimize resource use, vessel campaigns, and costs. The subsea foundation, used for the conductor, also supports SPS components such as tie-in points, flow bases, and protection structures, creating lighter, cost-effective solutions. This approach delivers the same functionality as multi-slot templates while maintaining simple interfaces for integration. The first satellite development using this strategy on the NCS was the Equinor Bauge Field, installed in 2020 and tied to the Njord production facility. Evolution of Integration The integration of SPS equipment with the well foundation follows a stepwise approach, increasing in complexity and benefits. Initially, subsea trees are mounted directly onto the wellhead with flowline tie-ins, common in regions without trawl protection. Next, Permanent Guide Bases (PGBs) are mounted onto the conductor at the onshore yard, as seen in Field Development A, saving rig time by defining well heading during installation. Further integration involves adding Flow Bases (FBs) with tie-in porches, requiring more extensive interface checks and testing, especially when combined with trawl protection. The final step is fully integrating PGBs or FBs into the well foundation, creating compact, lighter, and cost-efficient structures with tighter interface tolerances. Execution and delivery The execution and delivery of the well foundation technology involves several key steps: engineering and detailed design, fabrication of the well foundation unit, integration of SPS equipment like PGB or FB, conducting System Integration Tests (SIT), and finally mobilization and installation via an offshore construction vessel. The well foundation’s delivery timeline typically runs in parallel with other SPS equipment, taking 6-8 months for systems with trawl protection and 4-6 months for those without. Project acceleration can be achieved if load capacity is verified through geotechnical studies, streamlining design and manufacturing. Advantages The well foundation technology provides several key advantages by serving multiple purposes throughout the well's lifecycle. It acts as a carrier for the LPWHH/conductor extension during vessel installation, provides a strong foundation for the wellhead system during drilling (handling high loads from BOP weight and riser tension), supports infrastructure such as tie-in points and protection covers, aids in fatigue and drive/drift-off mitigation, simplifies conductor cutting during P&A, and allows for optimized well placement, replacing multi-slot subsea templates. Suction Anchor Based Well Construction The suction anchor-based well foundation offers several technical and economic advantages. It allows the conductor to be installed by a vessel ahead of rig arrival, saving 2-4 rig days. The conductor's load capacity and verticality are verified before drilling, with an excellent track record of less than 0.2 degrees deviation. The system provides fatigue and drive/drift-off protection for the wellhead and supports slim well design, enabling early kick-off for highly deviated wells. It also simplifies P&A cutting operations, reduces the environmental footprint, and allows scheduling flexibility by decoupling drilling from marine construction activities. Simplified Marine Operations and Project Schedule The suction anchor-based well foundation reduces marine operation costs and vessel size requirements compared to traditional four-slot templates, requiring smaller crane vessels (150-250 mT) and simplifying installation. Its lighter, simpler structure lowers downtime, weather-related delays, and emissions, while enabling more efficient integration with other operations and independent manufacturing of tie-in lines. Optimized Capital Expenditure (CapEx) The well foundation building blocks offer a flexible field development strategy, reducing initial CapEx and development risks by allowing incremental well additions over time. Compared to traditional four-slot subsea templates, single well foundations have significantly lower costs, especially in early development phases. The approach minimizes upfront investment, enables daisy-chaining of satellites, and supports early production, making it a cost-effective solution for both greenfield developments and satellite expansions. Further cost savings can be achieved through vessel operations and optimized marine campaigns. Accelerated Time to First Oil The well foundation technology offers significant time-saving benefits compared to conventional subsea templates by allowing early installation of the foundation, wellhead, and PGB/FB. This enables flowline installation and drilling to commence sooner, decoupling drilling from flowline activities and accelerating the overall project schedule. Long lead items, like the subsea tree system, can be installed later, optimizing vessel and rig availability. In brownfield projects, similar advantages apply. The potential value of accelerated production is demonstrated by a scenario where 4 weeks of early production at 5000 bbl/day and $85/bbl can result in an additional $11.9 million in revenue. Protection of SPS and Wellhead Equipment The well foundation technology improves the protection of wellhead and SPS equipment by directly connecting protection structures to the foundation, rather than relying on traditional well load relief systems that add cost and complexity. This approach enhances wellhead fatigue life and strength while reducing costs. Additionally, it provides an efficient platform for tie-in points and protection structures, ensuring better protection against thermal fluctuations and fishing equipment impacts during production. Optimized Well Placement Optimized well placement using suction anchor-based well foundations offers greater flexibility in positioning wells, reducing the required step-out distance and mitigating geohazard risks. This approach shortens the well lengths, simplifying trajectories and decreasing drilling time, casing, cement, mud, and rig use. A study on a five-well development showed an average reduction of 600 m per well, saving approximately 3 km in total drilled length, which also contributes to lower emissions and reduced rig time. Reduced emissions The adoption of well foundation technology significantly reduces emissions in subsea developments, especially in categories such as CO₂ emissions, human toxicity, and acidification. Comparative studies on wells drilled in the UK and Norway show that using a suction anchor-based foundation instead of a conventional conductor cuts CO₂ emissions by 21-44%. Moreover, the integration of a closed-loop circulation system during surface casing drilling, combined with zero discharge processes, further diminishes environmental impact. This setup simplifies operational processes, reduces rig time, and contributes to overall emission reduction. Summary The CAN-integrator serves as a bridge between drilling, well operations, and subsea facilities, enabling optimized processes for hydrocarbon field or CO2 injection projects. This innovative well foundation approach reduces costs, CO2 emissions, and accelerates returns on investment by utilizing proven equipment in a new way. The technology shifts operations from rigs to smaller vessels, minimizing vessel campaigns, and contributing to a 21-44% reduction in CO2 emissions (400-500 mT) for the top-hole section of each well. Further emission reductions are expected with optimized vessel operations as future projects progress. Reference Cardenas, C., Hansen, H.E.K., Hanssen, S., Blikra, H., Mathis, W., & Holen, O.K. (2021). Smart Well Foundation, the Cost Efficient and Environmental Choice for Field Developments.  SPE-209567-MS. Presented at the SPE/IADC International Drilling Conference and Exhibition. Retrieved from Society of Petroleum Engineers.

This summary  is based on the paper "Top-Hole Technology Overcomes Challenging Sand-Based Seabed Conditions and Enables Record Drilling Performance in an Offshore Exploration Well,"  presented by Camilo Cardenas, Hans Erik Kolstrup Hansen, Sigvald Hanssen, and Harald Blikra (Repsol Norge AS), Wolfgang Mathis and Ole Kristian Holen (NeoDrill A/S), and Arjen Kort and Youhu Zhang (Norwegian Geotechnical Institute) at the SPE/IADC International Drilling Conference and Exhibition, 2021. The full paper can be accessed through the Society of Petroleum Engineers . Essential Highlights CAN Technology Overview : The Conductor Anchor Node (CAN) was used to support well construction on the Kathryn exploration well, marking the first application in sand-based seabed conditions. The CAN integrates a conductor to form a stable foundation, using suction pressure to penetrate the seabed. Challenges and Solutions : The seabed at Kathryn included dense sand and boulders, making conventional methods risky. A CAN with an integrated conductor was chosen for its lower risk, reduced environmental impact, and cost savings. Contingencies like high-capacity pumps, water injection, and cyclic penetration were implemented to address potential installation challenges. Installation Success : The CAN was installed efficiently in 65 hours, faster than the planned 84 hours, reaching the required penetration depth with minimal issues. Real-time geotechnical monitoring was crucial for successful installation, confirming the CAN's load capacity on-site. Drilling Performance and Cost Savings : The project achieved record drilling time, completing the well in 13.54 days, saving 2.8 rig days compared to traditional methods. Top-hole construction costs were reduced by 51%, attributed to fewer materials, faster installation, and a simplified cementing process. Environmental and Safety Improvements : The CAN technology reduced CO2 emissions by 31%, minimized the need for cement and steel, and decreased the risk of handling large components on the rig. The pre-installed conductor allowed safer operations by avoiding manual handling of large tubulars. Abstract The successful implementation of CAN® technology in sand-based seabed conditions for this offshore exploration well in the North Sea demonstrated its effectiveness in overcoming geological challenges, such as boulders and dense sand layers. By providing a strong, pre-installed well foundation, the CAN reduced rig time, minimized uncertainties in cementing, load capacity, and fatigue, and significantly cut top-hole construction costs. Furthermore, the use of CAN technology enhanced operational safety and reduced the environmental footprint, making it a valuable solution for achieving high drilling performance in complex offshore conditions. Introduction Top-hole construction for subsea wells requires selecting the right solution based on seabed properties, expected loads, and well design. The CAN technology, introduced in 2006, reduces risks in top-hole construction by providing a verifiable load capacity through its suction anchor design. Initially used with conventional conductor installation methods, the CAN has evolved to integrate the conductor, simplifying installation and improving well stability. For the Kathryn exploration well in the North Sea, hard sand and high-strength sandy-clay conditions posed challenges for CAN deployment. This paper outlines the successful modifications made to ensure the CAN's installation, emphasizing its positive impact on safety, environmental footprint, cost, and drilling performance. Concept selection For the Kathryn project, three top-hole construction options were evaluated: drill and cement, CAN combined with drill and cement, and CAN with integrated conductor. Conductor jetting and hammering were discarded due to the presence of boulders. A risk-based comparison methodology was used to assess the main risks, including cement job problems, verticality issues, and accidental loads. CAN with integrated conductor had the lowest risk, particularly in mitigating cement and landing issues, and showed the potential to reduce environmental impact and cost by around 37%. Despite medium risks related to installation in hard sand, strategic mitigations were implemented, making the CAN with integrated conductor the preferred solution for its safety, environmental, and cost advantages. CAN implementation CAN Installation Principle The CAN installation method uses suction pressure to drive the structure into the seabed, a technique proven in various offshore applications like jacket foundations and FPSO anchors. The CAN consists of a large steel cylinder (the skirt) and a concentric conductor guide pipe. Initially, the CAN sinks into the seabed by its own weight, and then water inside the cylinder is pumped out to create a pressure differential, generating a downward force that pushes the CAN further into the soil. One of the key advantages of this method is that the load capacity can be verified in real-time during installation, providing more certainty than conventional methods. However, the risk of piping—water leakage between the suction compartment and open water—can occur in more permeable soils, potentially limiting penetration. Site-Specific Geotechnical Engineering Aspects at Kathryn At the Kathryn site, geotechnical assessments showed a mix of clean sand interlayered with clay and silt layers, presenting challenges for CAN installation. Four soil profiles were developed to capture these variations, and penetration analyses indicated that a minimum depth of 5.8 meters was needed for the required holding capacity. However, intermediate clay layers could lead to suction pressures as high as 1000 kPa, posing the risk of penetration refusal. Contingency measures were designed, including a high-capacity pump to increase suction, water injection to reduce resistance at the skirt tip, and cyclic penetration to deal with dense layers. A key modification involved closing the conductor pipe to create communication between the conductor and the suction chamber, increasing penetration force in case of refusal. Results CAN Operations CAN Installation Phase The CAN installation phase for the Kathryn well, conducted in July 2019, was completed efficiently, with all operations performed faster than planned, taking 65 hours instead of the expected 84. Key tasks included installing the low-pressure wellhead housing (LPWHH), testing equipment, and setting up a water injection system. The installation process was successful, with the CAN achieving a penetration depth of 5.8 meters within 14.5 hours of net installation time. Real-time geotechnical calculations were used to monitor and guide the operation, ensuring the penetration record matched the expected design. Despite minor challenges, such as a 0.2-meter shortfall in penetration depth, contingencies like activating the conductor's internal volume helped achieve the target depth without needing the water injection system or cycling. Retrieval of CAN unit For the Kathryn well, personnel from the CAN provider were actively involved in planning the drilling phase, focusing on preventing washouts and broaching during the spud phase. Operational parameters from previous CAN installations were used to guide the drilling program, including spud circulation rates, BHA diameter, conductor ID, and cementing details. This knowledge transfer ensured proper preparation for a successful drilling operation. Drilling performance The impact of the CAN technology with integrated conductor in the drilling performance of the Kathryn exploration well is analyzed in four different factors: drilling time, cost, environment, and safety. For each factor, it is discussed how this solution contributed to achieve the different project goals. Drilling time The Kathryn well was drilled in 13.54 days, making it the fastest well drilled by the operator in Norway and one of the quickest offshore exploration wells globally. The CAN with pre-installed conductor played a key role in this performance, saving 2.8 rig days compared to the conventional drill and cement method. Additionally, the P&A operation was streamlined by cutting the surface casing inside the CAN, eliminating the need for rig retrieval. The well achieved only 1.3% non-productive time (NPT), as top-hole risks were mitigated before rig arrival. Furthermore, using the CAN reduced the need for cementing the entire surface casing, minimizing the risk of losses and avoiding the use of more expensive cement slurries. Cost savings The use of CAN with a pre-installed conductor saved 2.8 rig days and additional costs associated with the 36" conductor casing, rental of 42" BHA, and 36" casing running equipment. Cement volume was significantly reduced from 241 m³ to 53 m³. Overall, the technology reduced top-hole construction costs by 51%, equivalent to saving two days of drilling operations, making it a key factor in achieving cost-related goals for the project. Environmental impact The CAN with integrated conductor significantly reduced the environmental impact compared to conventional drill and cement methods, cutting greenhouse gas emissions by 31% and reducing other pollutants such as NOx and particulate matter. This reduction, quantified by an LCA study from Asplan Viak (2020), was primarily due to the savings in rig time, cement, and steel. Overall, the CAN helped lower CO2 emissions by 432 tons and decreased the environmental footprint across all impact categories evaluated. Safety The CAN technology with a pre-installed conductor enhances safety by eliminating the need for rig crews to handle large diameter tubulars, as the structure is pre-installed by a vessel in a "hands-free" operation. This significantly reduces the risk of incidents during drilling. Additionally, the technology allowed the operator to reduce the size of the bottom hole assembly (BHA) from 42" to 17 1/2", further minimizing operational risks. Conclusion The CAN with integrated conductor was successfully installed on the Kathryn well, marking the first use of this technology in sand-based seabed conditions. Four installation profiles were evaluated, and measures were implemented to ensure success, resulting in a safe, efficient installation completed in 65 hours (vs. 84 planned). Continuous monitoring and real-time evaluation against geotechnical models were key to achieving the target depth and confirming the CAN's load capacity. This project demonstrated the versatility of the CAN technology to handle challenging conditions, cutting top-hole construction costs by 50%, reducing environmental impact by over 30%, and enhancing drilling safety. For more detailed insights, the full paper can be accessed through the Society of Petroleum Engineers . References Cardenas, C., Hansen, H.E.K., Hanssen, S., Blikra, H., Mathis, W., Holen, O.K., Kort, A., Zhang, Y. 2021. Top-Hole Technology Overcomes Challenging Sand-Based Seabed Conditions and Enables Record Drilling Performance in an Offshore Exploration Well . SPE/IADC Drilling Conference and Exhibition. SPE-204096-MS. Retrieved from Society of Petroleum Engineers.

This summary is based on the paper "How to Enable the Horizontal Development of Shallow Reservoirs,"  presented by Wolfgang Mathis, Harald Strand (NeoDrill AS), and Gerald Hollinger (OMV Norge AS) at the SPE/IADC Drilling Conference and Exhibition, 2017 . The full paper can be accessed through the Society of Petroleum Engineers . Essential Highlights CAN Technology Overview : The Conductor Anchor Node (CAN) is a suction anchor-based well foundation designed to support the conductor, BOP, and wellbore loads. It integrates a guide pipe to ensure vertical installation and provides a stable foundation for shallow reservoir development. The technology reduces rig time by allowing pre-installation of the CAN and conductor before the rig arrives. Wisting Central II Case Study : OMV (Norge) AS successfully drilled a 1.4 km horizontal section into a shallow reservoir (250 m below mudline) in the Wisting field. The CAN-ductor design, which features a shorter conductor (11 m), was essential for achieving the shallowest horizontal well ever drilled from a floating unit. The CAN allowed for significant vertical depth (TVD) for building the hole angle, enabling the successful penetration of the shallow reservoir. Operational and Cost Benefits : Installation by vessel, rather than rig, reduces costs, saves rig time, and enhances safety. The CAN eliminates the need for heavy cement jobs, large conductor handling, and guide bases. Average conductor setting time was reduced from 3 days to 1.2 rig days due to the CAN system. Geotechnical Considerations : Soil conditions at the Wisting location required careful assessment to ensure the CAN's load capacity and stability. The geotechnical assessment included evaluating shear strength and soil conditions. Successful Results : All well objectives were met, with the CAN providing stability and load-bearing capacity, leading to a simplified well architecture and lower costs. The project demonstrated the potential for CAN technology to reduce environmental impact and improve operational efficiency in shallow reservoirs. Abstract The Wisting Central II well, located in the Barents Sea, faced the challenge of drilling into a shallow reservoir just 200-250 meters below the mudline, making it difficult to build the necessary well angle for horizontal entry. To overcome this, OMV (Norge) AS utilized NeoDrill’s CAN-ductor  system, which integrates a short conductor (only 11 meters) into a suction anchor foundation (the CAN), providing the required load capacity. This innovative approach allowed for the successful drilling of a 1.4 km horizontal well at 250 meters TVD below the mudline, making it the shallowest horizontal well ever drilled from a floating unit. In addition to the technical success, the CAN-ductor system also resulted in significant cost savings by reducing rig time, eliminating the need for remedial cementing, and simplifying plug-and-abandonment (P&A) operations. Introduction The CAN well foundation, developed to improve top hole well construction, functions as a suction anchor with a guide pipe, allowing pre-installation by vessel to save rig time and ensure conductor stability. Initially deployed by Eni Norway in 2006 for deepwater wells, the CAN demonstrated unmatched efficiency, significantly reducing conductor installation time and mitigating risks related to well integrity. Since then, the CAN has evolved with 15 installations in depths of 125 to 1444 meters, proving to be a cost-effective solution for soft seabeds and conductor fatigue. A key application was Statoil’s Peon field, where the CAN provided a perfect soil-to-conductor seal, ensuring well integrity. The Wisting Central II well represents the latest example of the CAN’s potential in shallow reservoirs. CAN Design For successful CAN deployment, location-specific geotechnical data is required to determine penetration and load-bearing capacity. Since the Wisting well was an appraisal project, the CAN foundation was rented. CAN units of 6 meters in diameter, with heights between 7.5 and 11 meters, were available for use. Conductor Integration The conductor was integrated into the CAN at the workshop before shipment, following a series of welding and cementing steps. The conductor anchor was welded to the guide pipe, ensuring a total axial load capacity of 1050 tons, with cement filling the annulus for added stability. This method minimizes fatigue risks by avoiding hot work near the wellhead and uses standard components for quick assembly. Though slightly heavier than a standard CAN, the 93.5-ton structure was easily managed during installation. Guide Post Receptacles The CAN also includes integrated guide post receptacles, eliminating the need for a separate guide base. This feature further reduces costs and simplifies rig operations during the installation process. Geotechnical Assessment Before installing the CAN, a geotechnical analysis of the seabed was performed to determine the required CAN dimensions and load-bearing capacity. CPT data from nearby locations showed variability in soil strength, with favorable conditions at CPT 10 but stronger formations at CPT 03, which could limit penetration. A geotechnical correlation confirmed that a consolidated layer at 27 meters would not affect CAN installation at the planned depth of 7.5 to 11 meters. CAN Dimensions and Load Capacity Among the available CAN units (6 meters in diameter), the 11-meter CAN was selected due to its load capacity, which exceeded design requirements by more than double, providing a safety factor greater than 2. Backup Scenarios In case of unexpected increases in soil strength, two additional scenarios were analyzed. Even with early refusal at 6.6 meters, the CAN maintained sufficient capacity with a safety factor of 2.22, ensuring it would meet load requirements. CAN Installation The CAN was installed at the well location in December 2014, but the ROV survey revealed a significantly sloping seabed, causing a 3.3° tilt in the CAN. To correct this, the CAN was partially lifted, and the installation vessel was repositioned to reduce the tilt. After adjustments, the final inclination was brought to 0.18°, well within the acceptable limit of 1.0°. The CAN achieved full penetration of 11 meters, with a slope of 0.9 meters across its diameter, equivalent to an 8.53% seabed slope. The final installed position was within target range, with a slight deviation in orientation to 171.30° (from the target of 180°). Geotechnical Back-Calculation After the CAN installation, recorded data was used to update the geotechnical model and verify the actual load capacity of the CAN. This is a unique advantage of the CAN system, allowing precise verification of load capacity. The back-calculation matched the measured underpressure to soil parameters at the site, adjusting for initial data uncertainties due to CPT tests from distant locations. Deviations in the data were attributed to setup delays and the sloping seabed. The final load capacity was higher than predicted due to increased resistance from the CAN lid coming into contact with the seabed at 10 meters depth. Drilling Phase The Wisting Central II well successfully demonstrated horizontal drilling in a shallow reservoir, achieving a 2.5° inclination at 50 meters and completing a 1.4 km horizontal section. The CAN installation confirmed that shallow-set conductors (10 meters) are sufficient, with no borehole instability. The CAN's verified inclination (0.18°) before rig arrival saved rig time, and no movement was detected during the 70 BOP days. Installing the conductor by vessel reduced handling, HSE risks, and eliminated the need for a cement job or guide base. The simplified casing cutting process and flexible installation schedule further minimized risks and costs. Results and Conclusions The Wisting Central II well achieved all its objectives, becoming the shallowest horizontal well drilled from a floating unit. A key factor was the integration of the conductor into the CAN foundation, reducing the conductor from four joints to one and providing the necessary TVD for the high dog leg trajectory. Despite the lack of CPT data at the spud location, the CAN performed as expected, delivering the required load capacity. Cost Savings The CAN system contributed to significant cost savings, reducing rig time by 1.2 days, or 40%. Savings came from avoiding extra conductor joints, running tools, BHA, cement jobs, and guide bases. The system also reduced P&A time and non-productive time risks. Further Developments There is potential for further optimization by reducing casing sizes, which would lower construction costs and enable greater dogleg angles. The CAN supports the conductor, significantly reducing bending moments, and allows for integrating the kick-off point, giving better control over well deviation. Acknowledgements The authors would like to thank OMV (Norge) AS for allowing to publish the information presented in this paper. For more detailed insights, the full paper can be accessed through the Society of Petroleum Engineers . References : Mathis, W., Strand, H., & Hollinger, G. (2017). Case History: How to Enable the Horizontal Development of Shallow Reservoirs . Presented at the SPE/IADC Drilling Conference and Exhibition, The Hague, Netherlands, 14-16 March. SPE-184667-MS. Retrieved from Society of Petroleum Engineers .

This summary is based on insights from the paper "New Well Foundation Concept, as Used at a Norwegian Sea Well,"  presented at the SPE Arctic and Extreme Environments Conference & Exhibition, Moscow, 2011. The original paper was authored by Trond Sivertsen, SPE, Det Norske Oljeselskap ASA, and Harald Strand, SPE, NeoDrill AS. The full paper can be accessed via the Society of Petroleum Engineers . Essential Highlights CAN Technology Overview : The Conductor Anchor Node (CAN) is a new suction anchor-type well foundation designed to support heavy blowout preventers (BOPs) and Christmas trees. It offers high load capacity and enhances well stability, especially in deepwater and Arctic conditions. Operational Benefits : Pre-Rig Installation : Allows conductor installation before the rig arrives, reducing rig time and top-hole construction costs. Accidental Load Mitigation : Provides a high bending stiffness, directing accidental loads above the BOP, thus protecting the well structure. Enhanced Cementing : Shorter conductors and improved conditions lead to better cement quality and reduced cement volume. Environmental and Safety Advantages : Reduced Environmental Footprint : Smaller vessels emit less CO2 and NOx, and there is reduced cuttings and cement disposal. Improved HSE Performance : "Hands-free" conductor installation minimizes manual handling and enhances safety. Field Applications : Demonstrated in water depths of 270-1150 meters on the Norwegian Continental Shelf, achieving successful installation even in challenging seabed conditions. Versatility and Reusability : The CAN units are durable and can be reused for multiple well installations, providing cost efficiency over time. Abstract A new well foundation system, the Conductor Anchor Node (CAN) , has been developed to improve well stability and safety, particularly for handling heavy Blow Out Preventers (BOPs) in deep water and arctic environments. The CAN mitigates fatigue risks and accidental overloads, such as rig drive-offs, by providing substantial load capacity through its large cross-sectional area and soil interaction. It also reduces environmental impacts by limiting cuttings and cement disposal, which is critical in sensitive marine areas. The CAN enables pre-rig conductor installation, cutting rig time and top-hole construction costs, and has been successfully deployed in multiple full-scale applications on the Norwegian Continental Shelf. Introduction As rig day rates rise, there is a growing need to reduce rig time, particularly for drilling the top-hole section of wells, which doesn't require pressure control. To address this, a more efficient conductor installation method is needed. Additionally, current well designs lack the capacity to handle accidental loads, such as those caused by rig drive-offs, which can result in wellhead failures. The Conductor Anchor Node (CAN)  was developed as a solution, allowing for pre-rig conductor installation and providing mechanical support. The CAN enhances the well's lateral load capacity and transfers potential damage points above the BOP, protecting the wellhead and conductor from accidental overloads. Technology description The Conductor Anchor Node (CAN)  is a suction anchor designed to improve well stability, featuring a cylindrical shell with a strong lid and a conductor guide that extends into the soil. The CAN, weighing 60-80 tons, is installed using a DP vessel with a heave-compensated crane. Once placed on the seabed, an ROV pumps out water from the CAN, creating pressure that pushes it further into the sediment, providing substantial load capacity. The large surface area allows for high push-in forces with moderate pressure, optimizing installation efficiency. The CAN also enables efficient pre-rig conductor installation. The conductor is pre-assembled onshore, lifted by a crane, and stabbed into the CAN, allowing for cost-effective installation without the need for drilling and cementing. Alternatively, the conductor can be installed by jetting, with the CAN providing stability and predictability for shorter conductors. The CAN offers superior load capacity, reducing cement usage and well construction costs while mitigating environmental impact through less waste and emissions. Key advantages include high axial and lateral load capacity, increased bending stiffness, reduced well fatigue, and safe conductor installation. This technology supports faster production and lower top-hole construction costs while ensuring safer and more efficient well operations. Operational experience CAN Installation The CAN installation was successfully completed in less than 20 hours at a soft seabed location, ensuring high load capacity to support the heavy BOP of the Aker Barents rig. The CAN was installed with two transponders for accurate placement, achieving nearly full penetration (10.5m vs. 11m). A pressure differential of 2 bar generated about 550 tons of push-in force, testing the CAN's vertical load capacity. The installation weather window required 4 hours with <3.5m HS, and ROV operations were successfully performed. The conductor was drilled, installed, and cemented without issue, significantly reducing cement volume and time. CAN Recovery After drilling, the well was plugged, and the CAN was recovered by reversing the installation process. The ROV pumped water into the CAN, lifting it 60% of its embedded length before being fully freed from the seabed. The CAN, along with the cut 30” and 20” conductors, was lifted to the surface and placed onboard. The recovery process went as planned, with the CAN and components cleaned and prepared for reuse. HSE Performance Safety precautions were taken by installing bumper bars to control the CAN’s landing on the vessel deck. A 10 cm thick clay layer indicated high steel/soil friction during recovery. The entire operation was completed without any HSE incidents, demonstrating the CAN's ability to be installed and recovered safely. The “hands-free” conductor handling method improved work conditions for the crew, reducing manual labor on the rig. The CAN installation by vessel also minimized the environmental footprint by reducing emissions and cuttings disposal, using smaller vessels. Conclusions The CAN concept offers safer and more cost-efficient well construction by enabling the installation of higher load capacity wells compared to conventional methods. Its superior bending stiffness ensures accidental loads are directed above the BOP. In arctic and cold climates, the CAN reduces conductor length and cement volume, shortens cement jobs, and improves cement quality by keeping the conductor motionless during setting. Additionally, the CAN reduces the environmental footprint of conductor installation, making it a more sustainable alternative to traditional rig installations. Acknowledgement Det norske Oljeselskap’s active participation in preparing and planning this demonstration project, which resulted in technically high quality execution of the vessel operations, were highly appreciated by all parties involved. For more detailed technical information, the full paper is available through the Society of Petroleum Engineers. References Sivertsen, T., & Strand, H. (2011). New Well Foundation Concept, as Used at a Norwegian Sea Well.  Presented at the SPE Arctic and Extreme Environments Conference & Exhibition, Moscow, Russia, 18–20 October. SPE-149548-MS. Retrieved from Society of Petroleum Engineers .

This summary is based on the paper "Conductor Anchor Node Optimizes Efficiency of Riserless Deepwater Exploration Drilling,"  presented by E. Kopperud, A. Knudsen, S.J. Dybvik, F. Hardinges (Det norske oljeselskap ASA), and W. Mathis (NeoDrill AS), published in the Journal of Petroleum Technology  in 2017. The full paper can be accessed through the Society of Petroleum Engineers at Journal of Petroleum Technology . Essential Highlights Technology Overview : The Conductor Anchor Node (CAN) technology was introduced for deepwater drilling to optimize riserless operations. It acts like a suction anchor to stabilize the well's conductor on the seabed. Operational Efficiency : The CAN technology reduces rig time and costs by allowing preparatory work to be completed before the drilling rig arrives. This streamlines operations and accelerates well startup. Case Study - Ivory Well : In the Ivory exploration well in the Norwegian Sea, the CAN system shortened the conductor length needed, saving significant rig time. It allowed for quicker jetting of the conductor and minimized weather-related delays. Results : Using CAN technology led to a significant time savings of 7.3 days compared to traditional methods during the riserless drilling phase, enhancing the overall efficiency of the drilling operation. Introduction The Conductor Anchor Node (CAN)  technology, developed by NeoDrill, was introduced for Centrica’s Ivory deepwater well in the Norwegian Sea to optimize riserless operations. The CAN, a large steel cylinder, acts like a suction anchor by setting into the seabed to secure the conductor (top-hole casing). It was installed using a dynamically positioned (DP) vessel  ahead of the rig’s arrival, saving rig time and simplifying logistics. Pre-installation steps, such as placing marker buoys and transponders, were completed in June 2014, enabling efficient startup when drilling began in October. A pilot hole was drilled 50 meters from the CAN to assess soil strength and ensure safe operations. All riserless activities were optimized using dual derricks to reduce rig time and maximize efficiency. Well Design and challenges The well's strategy was to complete pre-rig work to minimize weather risks and optimize operations. NeoDrill preinstalled the CAN, reducing the conductor length to 50 meters compared to the conventional 80-100 meters. Conductor jetting, the quickest method, was used without requiring cementing or tripping. The CADA tool  enabled continuous drilling, and the CAN ensured safe conductor landing without waiting for soil consolidation. A pilot hole was drilled 50 meters from the CAN to confirm jetting feasibility. Ivory operational summary The pilot hole was drilled by an auxiliary rig, as the main rig needed to remain available for landing the BOP and riser. The conductor was positioned in the moonpool to keep the main rig free. The BOP and riser were prepped offline while the auxiliary rig jetted the conductor and drilled ahead for the next section. The BOP was landed just before surface casing was cemented. The CAN installation took 4 to 5 days, with the full penetration achieved in 4 hours, and a final inclination of 0.42°. Preinstalled transponders and buoys saved rig time. Pilot hole A pilot hole was drilled 50 meters southwest of the main location to assess the feasibility of conductor jetting. Data collection was challenging due to rig heave, but a weight on bit (WOB) of 5 tons between 1495 m and 1505 m indicated a stronger formation. A significant change in formation strength was observed at 1501 m. Logging confirmed a clay sequence at the bottom, allowing the conductor jetting operation to proceed. The pilot hole was drilled to a vertical depth of 2200 m. Conductor jetting The jetting operation involved a 49.8-meter conductor run with a NeoDrill hanger to land into the CAN. The CADA tool was used to drill ahead, and the conductor was kept moving every 2-3 meters to prevent sticking. After landing the casing, the CAN's axial load capacity allowed immediate drilling without a soaking period. This approach saved 7.3 rig days compared to the expected plan, demonstrating the efficiency of using the CAN with a short jetted conductor in dual-derrick operations. Fig 2: The conductor housing with the CADA tool landed inside the CAN. Conclusion The CAN technology, deployed in the Ivory deepwater exploration well, optimized well construction operations by reducing the time and cost of riserless sections. By preinstalling the CAN, jetting operations became more efficient, allowing for shorter conductor lengths compared to traditional methods, and minimizing risks associated with soil consolidation and conductor movement. The CAN's axial load capacity supported operations without requiring extended cementing processes. The overall results demonstrated significant time savings, with 7.3 rig days spared compared to expectations. This method not only increased operational efficiency but also reduced environmental impact and enhanced safety, making it a key solution for riserless drilling in deepwater conditions​ For more detailed insights, the full paper can be accessed through the Journal of Petroleum Technology . References Kopperud, E., Knudsen, A., Dybvik, S.J., Hardinges, F., & Mathis, W. (2017). Conductor Anchor Node Optimizes Efficiency of Riserless Deepwater Exploration Drilling . Journal of Petroleum Technology. Retrieved from https://jpt.spe.org/conductor-anchor-node-optimizes-efficiency-riserless-deepwater-exploration-drilling .

Bjørn brings a wealth of experience in mechanical design and engineering to our team. With over nine years in the industry, he has been deeply involved in the entire lifecycle of product development—from concept and prototyping to production-ready designs and final assembly. His recent experience includes designing, engineering, and managing hydraulic power units (HPU), workover control systems (WOCS), and chemical injection systems for topside installations.  Throughout his career, Bjørn has contributed to several notable projects, including designing tools for Husqvarna’s assembly line to improve manufacturing processes, developing welding jigs for Laxå Special Vehicles, and working on the structural design of the Lync & Co tailgate at CEVT AB. At FlyPulse AB, he played a key role in designing the clam-shell body for an autonomous drone intended for delivering defibrillators to rural areas.  Bjørn holds a BS in General Engineering with a focus on Mechanical Systems and Micro-Electronics from Montana Tech, and he further specialized in mechanical design in automotive engineering at Lernia AB. His strong technical skills span a range of design software, including Inventor, Catia V5, Solidworks, and AutoCAD, along with expertise in geometric dimensioning and tolerancing (GD&T), electromagnetics, and mechatronics.  We are excited to have Bjørn join us and look forward to his innovative contributions to our projects.  Welcome to the team, Bjørn!

The first CAN-ductor ever to be installed was done in the Barent Sea December 2015 with great success marking a new era for the CAN technology. By integrating the conductor to the CAN it added a new value case where 2-4 rig days were removed from a typical top hole establishment in addition to being a much stronger and more reliable wellhead foundation. This summer another 3 off CAN-ductor units were installed for one of our customers as part of their exploration program in the Barents Sea. In total 4 off CAN-ductor units were ordered and turned around on an accelerated schedule ready for shipment on the quay side 1st of June. Our trusted partner, Randaberg Industries, professionally ramped up their production line to modify our rental CAN units to suite the geo-technical conditions on the locations provided by the customer. That involved primarily modifying the length of the CAN skirts and integration of the customer provided low pressure wellheads. Installation cost of any installation going subsea is normally critical to the overall project cost. Different ways for bringing the CAN units from Stavanger to the Barents Sea and installed was considered. A decision on brining the units on a coastal liner was made and all 4 units was thoroughly stacked and secured horizontally before shipped to Hammerfest and Polar Base where they were offloaded and upended on key side. The installation vessel, Olympic Ares, loaded and secured 2 off units before going out installing the units on their specific locations at roughly 400m of water. Installation time per CAN unit was in average 18 hours from vessel arrived location until leaving again after successful installation. Customer selected the CAN-ductor for various reasons: Reduced risks Safety & environment no heavy bottomhole assembly or conductor handling / lifting in red zone no in moonpool man riding no cuttings to seabed from top hole Operational risks Engineered wellhead foundation removing risk for out of verticality No wobbling wellhead due to BOP loads Extended wellhead fatigue life time Removes wating on weather for top hole section Simple cutting of wellhead during P&A Cost Removes 2-4 rig days Allows conversion from exploration to production CAN-ductor designed to be converted to production well later if found commercial discover 100% recyclable We are now working with customer to finalize last well location before the 4th CAN-ductor is installed. In the mean time we congratulates the customer with the current installation success and wishing them all the best of luck in the coming exploration drilling on these wells now just wating for the rig to arrive.

With extensive experience across various offshore roles, including client representative, offshore manager, shift supervisor, and installation supervisor, Pål Erik brings invaluable expertise to maintain our high-quality offshore operations. Since 2020, he has proven his capabilities with Neodrill, contributing to the successful installation of over 20 CANs. We are excited to now have him fully on board! With a background in Nautical Science, Pål Erik served his cadet period with Havila Shipping on board supply, anchor handling, and subsea construction vessels before becoming a mooring equipment representative during semi-sub rig moves. He also has 5 years of logistics experience from working as a harbor inspector in his hometown of Kristiansund. Before joining Neodrill, Pål Erik worked as a senior marine advisor on a wide variety of offshore projects, from the planning stage to execution. His diverse background enriches his career in the subsea industry. Based in Trondheim, he will provide a fresh perspective and drive excellence in our projects. We look forward to our continued collaboration with you, Pål Erik. Welcome aboard!

The oil and gas industry's evolution has always been about pushing boundaries, exploring unknown territories, and harnessing technology to unlock the earth's energy resources. At the heart of this exploration and production activity lies the critical importance of a robust foundation - particularly in subsea developments. Neodrill's CAN-integrator technology stands at the forefront of this innovation, redefining what's possible in subsea wellhead systems. In the image below the top of the CAN is fitted with OneSubsea's deflector base to the left and with Astrimar's (www.astrimar.com) design and solution to the right. Subsea Wellhead and the Innovation behind CAN-integrator Subsea wellheads are vital components in offshore drilling, serving as the interface point between the seabed and the drilling operations above. These structures must withstand extreme conditions and pressures, making their design and installation critical for the safety and success of drilling projects. Enter the CAN-integrator by Neodrill, a revolutionary approach that not only strengthens the subsea well foundation but also extends its fatigue life significantly. Derived from the original CAN-ductor technology, the CAN-integrator is engineered to support the well throughout its lifecycle, accommodating the unforeseen extension of field production life due to advancements in Enhanced Oil Recovery (EOR) technologies and the discovery of nearby resources. Advantages of CAN-integrator in Oil and Gas Field Services The CAN-integrator system introduces numerous advantages over traditional conductor systems. By design, it reduces operational costs and environmental impact. Implementations have shown that it can save operators 2-7 rig days on average, a substantial cost-saving in the high-stakes environment of offshore drilling. Moreover, the reduced need for large and heavy conductors, bottom hole assemblies (BHA), and volumes of cement not only minimizes the logistical footprint but also the project's environmental impact. Subsea Solutions and Systems Enhanced by CAN-integrator Integrating Subsea Production Systems (SPS) with the CAN-integrator has yielded considerable scope savings. The design allows for the inclusion of guide bases and flow bases directly into the CAN top, streamlining installation and reducing the need for additional structures on the seabed. This integration capability makes the CAN-integrator particularly suited for single and dual slot developments, as well as more complex daisy chain or in-line T developments. Subsea Development Strengthened by Technology The strength and versatility of the CAN-integrator have made it a preferred choice for operators looking to future-proof their subsea wells. Its ability to withstand the anticipated casing, BOP, riser, and environmental loading for the life of the field has been a game-changer, providing a level of reliability and safety previously unattainable. Sustainability and Environmental Benefits of CAN-integrator Perhaps most notably, the CAN-integrator aligns with the industry's growing commitment to sustainability. Its installation process, which eliminates the need for drilling tophole, running, and cementing conductors, significantly reduces CO2 emissions and environmental disruption. Furthermore, the system's design ensures that 100% of the CAN-integrator can be recovered and recycled at the end of the field's life, contrasting sharply with the less than 10% recovery rate of conventional conductors. Enabler for potential future rigless exploration wells With the rigless CAN-ductor well foundation, a platform for future rigless exploration well drilling is created. Leveraging the CAN-ductor further well sections may come in place by use of cheaper well intervention vessels and technologies like casing drilling and coil tubing drilling. Considering well barriers are maintained, this could be a game changer for cheaper and more environmental exploration drilling. Conclusion The CAN-integrator by Neodrill represents a significant leap forward in subsea development technology. By offering a more robust, cost-effective, and environmentally friendly solution, it sets a new standard for the industry. As we continue to push the boundaries of what's possible in offshore drilling, technologies like the CAN-integrator will be pivotal in ensuring that these endeavors are sustainable, safe, and successful. "With CAN-integrator, we say 'Yes, we CAN!' to a stronger, safer, and more sustainable subsea future."

The Norwegian Continental Shelf (NCS) has been driven by a strong standardization process over the last decade led by the bigger operators. The purpose of this process has been to reduce costs primarily in the early phases, but generally also over the full project phase, for any field development. Standardization Outcomes The outcome of the standardizing process has been the NCS 17+ subsea production system building blocks. These consist of core elements like templates, 6, 4, 2, or single slot solutions, manifolds, vertical X-mas trees, and associated control systems. The time to start manufacturing these elements has become much shorter, and due to the reduced need for field-specific engineering, the cost has also been reduced considerably. Challenges of Standardization The drawback of standardizing is the risk of preventing innovation and technological improvements. Still, smaller incremental improvements can be achieved, allowing the combination of known technologies into new system setups. Neodrill was recently tasked to look at such an incremental development with an Operator on the NCS. Targeting Smaller Discoveries The Operator was targeting smaller discoveries around an existing operating asset and required cost-efficient solutions to ensure a stronger or sufficient return on investments in the event of a development. These discoveries typically hold marginal resources that would not justify a separate field development but would be a valuable addition to the existing production assets. Synergies with Exploration Phase Secondly, the operator would like to draw synergies with their exploration phase. If a discovery was made, the operator wanted the option to simply convert this to a production well. This would typically apply to a gas discovery primarily, but also in some cases for an oil discovery, depending on the location of reservoir penetration. Utilization of Current NCS 17+ Standard In line with current NCS 17+ standardizing, the same VXT used for template development wells should be used for these single well producers. This adds some complexity to the flowbase to allow for flow line mandrel travel, which again increases the size of the flow base. The current NCS 17+ single slot solution calls for a 4-suction pile structure for this flow base to sit on, with an associated over-trawl protection structure. Modular Solutions by Neodrill In the study conducted by Neodrill, a modular solution was found that allows for a CAN-ductor to be converted to a single slot CAN-integrator in the event the operator decides to convert the exploration well into a producer and tie it back to an existing facility. As the biggest loads on the CAN-ductor are seen during drilling with full casing and BOP/riser loads, it was not considered challenging to add an adapting structure on top of the CAN-ductor to integrate the single flowbase and VXT on top. The adapting structure will have fixed interface points towards the CAN-ductor at the bottom, and the SPS provider can interface its flowbase and VXT on the top in relation to wellhead stickup on the CAN-ductor. Future Prospects Due to the modular setup of the CAN-ductor to CAN-integrator conversion kit, Neodrill, together with the Operator, sees considerable upsides going forward in developing smaller discoveries. At the same time, they are reducing CAPEX and OPEX costs with a smaller environmental footprint by leveraging this new solution.