Search Results

We are dedicated to developing and delivering solutions which support carbon efficient production. Our proprietary CAN technology, and wider subsea solutions, all reduce the CO2 footprint of top-hole construction compared to traditional methods. Proven to reduce CO2 by at least 30% compared to conventional drilling, we believe our technology is the best choice available for reducing emissions and supporting carbon neutral operations in top-hole well construction. How CAN technology reduces CO2 emissions vs conventional methods Reduces rig time by 2-4 days on average, which decreases the combustion of fossil fuels during operations Reduces the need for steel in well casings Eliminates top-hole cuttings and the disposal of cuttings Removes the need for spud mud drilling fluid CAN units are reusable and have an expected lifetime of 10 wells “Environmental impact is a concern that will only grow in importance and we are very proud to be playing a role in helping the industry transition to cleaner, safer and greener processes. We look forward to working with clients to further improve efficiencies and reduce their environmental impact using our patented technologies.” Jostein Aleksandersen, Neodrill’s Chief Executive Officer The effectiveness of our CAN-ductor technology to reduce CO2 emissions has been proven and quantified by two independent studies, to date. Looking at a range of environmental factors, not just CO2, we are proud that the CAN-ductor drilling well offers a 21 – 44% lower environmental impact compared to that typically experience on a conventional drilling well. Learn more about how CAN reduces environment impact

A month ago, during the SPE Norway Subsurface Conference in Bergen, we presented a paper titled “Smart Well Foundation, the Cost Efficient and Environmental Choice for Field Developments.” In this presentation we demonstrated the ability to use field proven SPS and CAN technology building blocks, pre-installing equipment on the CAN such as guide base and flow base, to enable: Conductor installation before rig arrival Verified load capacity and inclination before rig arrival Early kick-off Early metrology Schedule flexibility, decouple drilling and marine activities Reduced CO2 emissions SURF operations prior to drilling the well – accelerated time to first production Optimized well placement – shorter wells No unused spare slots in template Superior wellhead support Trawl loads directly into CAN foundation Reduced CapEx

A year of growth In 2022 we saw the increased awareness of the CAN technology for field developments, resulting in our second field development contract internationally. Furthermore, an ever-growing number of Clients have started to realise the cost and CO2 reduction benefits from the CAN technology resulting in several more Clients and frame agreements. Lastly we saw that the introduction of installation campaigns was adopted swiftly by the market, with the successful execution of the final 7 CAN installation campaigns in October and November. Support the energy transition The energy sector faces the combined challenges of secure, cost-efficient supply of energy while reducing emissions in line with the European taxonomy regulations. We are committed to align with these needs by providing a robust well foundation replacing the traditional conductor based top hole section with the CAN-ductor, reducing cost and CO2 emissions by approximately 500 tons per well. Looking into 2023 We see significant interest to use the CAN technology to reduce cost and CO2 emissions, both in Norway and internationally. We are currently planning our spring installation campaign for Q1, and both fabrication and engineering are ongoing. We plan on increasing our organization to handle the increased work load, as well as strengthening our partnerships and supplier network. We would like to thank all our Clients, suppliers, and partners for making 2022 the most busy and successful year of Neodrill’s more than 20 years history and wish you all a prosperous New Year.

This summer, our Senior Project Engineer Huaijiang Chen at Neodrill starts a new adventure. Along with his family, he's embarking on a journey Down Under, where he'll be working for the next two years. In Australia, Chen will continue with many of his current responsibilities for Neodrill, while seizing the opportunity to enhance his design skills and evolve further as an engineer. With a Bachelor's degree in Mechanical Engineering from China University of Petroleum and a Master's degree in Petroleum Engineering from the University of Stavanger, Chen has consistently been a pivotal member of our team. When not engrossed in mechanical design and 3D modeling, you'll find him exploring the great outdoors, cycling, hiking, or fishing. As Chen embarks on his journey, we wish him the best of luck. His positive energy will be deeply missed while he's away. Safe travels, Chen! We can't wait to hear about your adventures!

We installed our first CAN from a Jack Up rig this weekend for one of our international clients. This is Neodrill's first application from a Jack Up rig and show one of the various application for the CAN technology. The CAN was mobilized from our manufacturer Randaberg Industries with a supply vessel, transported to the field and picked up by the Jack Up using the drill string. The installation went very smooth into sandy seabed soil, and is now ready for the drilling operation.

Conventional subsea single production well design requires the well to be drilled and completed with the drilling rig (vessel) before flow lines pull-in, connection of umbilical’s, etc. are undertaken with other specialized vessels. This causes not only time delay between well drilling/completion and production start-up, but also adding for way more CO2 emissions. By pre-rig installing a single well foundation with integrated conductor, manifold, pipeline and umbilical tie-in points, this additional CO2 emission and costly time delay can be reduced, and essentially facilitate instant production. Please join us for the joint Neodrill/BakerHughes presentation in room Klokkeklang, 15 June, 15:30 with the title “Satellite tie-back solutions with reduced CO2 emissions and a smaller environmental footprint»

Based on lessons learned from multiple CAN-ductor installations, Neodrill have been working closely with one of our key clients to create the latest generation of CAN-ductor with an integrated CTP. This is first of the new generation which was successfully installed on the NCS as a single lift from an MSV in early January 2022 for the same Client. The result of implementing a series of enhancements has yielded operational time savings of 65% when directly compared to the previous installations the NCS and further reduced HSE exposure to personnel and the environment. CTP overview: The new CTP is a hinged design that can be quickly opened and closed in two directions using a single guide wire c/w a standard Wepco or Imenco Guide Wire Anchor deployed either from the rig or a vessel. For further details, The main operations of the new CTP and system interfaces are presented in animation below.

By combining Neodrill and Enhanced Drilling technologies zero discharge during drilling of subsea wells is possible. See short animation in link below. Here is a link to our website where you can get a copy of the recorded webinar. https://resources.enhanced-drilling.com/webinar-reduce-carbon-emissions-and-achieve-zero-discharge

Introduction The CAN well foundation concept was developed to improve the conventional top hole well construction process. It has the basic form of a suction anchor with an additional guide pipe. The installation is performed by vessel prior to rig arrival which provides the operator with more flexibility in planning and saves rig time. Furthermore, it enables pre-installation of the conductor, or can act as a guide to ensure vertical installation of the conductor by jetting or driving (top or toe). The CAN also acts as the primary support for the BOP and subsequent loads induced during the wellbore construction (axial, lateral as well as bending loads), in addition the risk of unstable conductors due to poor primary cement jobs or lack of verticality are mitigated. The first installations were undertaken by Eni Norway in 2006 in order to enable safe jetting of conductors for their deep water wells Gemini in 1100 m and Cygnus in 860 m water depth. As the well loads were to be taken by the CAN, the use of short conductors (3 and 2 joints only respectively) plus drill-ahead features of the jetted conductor running tool enabled hitherto unmatched conductor installation efficiency at these water depths; both were installed within 24 hours each. This compares favourably with the average conductor setting time in deep-water (> 800 m) at that time of 7.4 days for comparable wells (this average included all 18 previously drilled deep water wells, of which several had to be respudded, resulting in significant cost overruns. Arguably, the average time has dropped since, to typically 2.17 days as reported on the NCS for medium water depths). Further, risks related to conductor stability, verticality and load carrying capacity were also fully mitigated. Based on this novel and successful method of spudding a well, the concept was further developed into a stand-alone, proven technology as of today, with 15 installations to date in water depths ranging from 125 to 1444 m. The purpose of the third CAN application was to ensure best possible conductor to soil seal for the very shallow gas reservoir Peon (Statoil), with top of reservoir only 170 m below seabed. Just relying on cementing the conductor in place was evaluated as being a significant well integrity risk. This was resolved by first installing a CAN, through which a conductor was driven with a subsea hammer, using the same installation vessel for both tasks. This solution offered a pre-installed conductor and a perfect soil-to-conductor seal which ensured well integrity. These projects established the CAN as both a problem solver and cost saver for soft seabed and conductor fatigue related problems (Sivertsen 2011). However, as a result of further technology development/extension, new areas of CAN applications evolved, which has resulted in 15 installations, with the most recent application for Wisting Central II as an example of the CAN technology potential. The background objectives, preparations as well as operations execution of this unique well are discussed in further detail below. CAN Design To ensure a successful deployment of a CAN or suction anchor, location specific soil property information is needed. This geotechnical information has to be analysed and used as a basis for calculating the achievable CAN penetration as well as the achievable load bearing capacities of the CAN. As the well to be drilled was an appraisal well and would be removed after logging and production testing, the well foundation was to be rented for the duration of the well. For this project CAN units of 6 m diameter were on stock in different heights ranging from 7.5 m to 11 m. Conductor Integration The integration of the conductor was done in the workshop prior to shipment to the mobilization port. Fig. 1 shows a sketch of the CAN with integrated conductor and 36 in. LPWHH (low pressure wellhead housing) as installed on the seabed. The integration of the conductor is based on the following construction steps (in reference to Fig. 1): · Basis is a standard CAN design with guide pipe (44.5 in. ID). · The conductor anchor is welded to the guide pipe at the lower end. This element is designed to transfer 350 ton from the conductor into the guide pipe. · A centralizer is mounted near the top of the conductor. This centralizer fixs the position of the conductor until the cement is in place. · The conductor is lifted into the guide pipe and welded to the conductor anchor at the bottom. · The annulus between the guide pipe and conductor is filled with cement. The cement provides an axial load capacity of 70 ton/m, resulting in about 700 ton over the cemented height of the conductor. In combination with the conductor anchor the total axial load capacity is therefore 1050 ton. This integration method was chosen for simplicity and has the following advantages: · No hot work on or close to the conductor housing, therefore no introduction of new hot spots that would compromise the fatigue life of the wellhead system. · The conductor is welded at the bottom where only a few percent of the loads are remaining. · Short lead time as all elements are standard off the shelf components and will fit all subsea wellhead supplier wellheads. · The conductor integration is done within a couple of days in a workshop. This ensures both, an efficient work process and a controlled environment. o Note: This design is slightly heavier than a standard CAN due to the added steel and cement weight, however the total weight of the structure is easily handled by supply bases as well as installation vessels. The total weight of the structure as shown in Fig. 1 is 93.5 ton versus 80 ton for a standard CAN of the same dimensions. Figure 1 – Section through CAN "as installed". Fig. 2 shows the detail with the top of the conductor cemented into the CAN, Fig. 3 shows the assembly while deployed through the splash zone. Figure 2 – Conductor integrated in to CAN Figure 3 – CAN deployed through splash zone Guide Post Receptacles The CAN has guide post receptacles integrated into the top. This further contributes to cost savings and simplifications of the rig operations as no guide base is required to be run. Geotechnical Assessment In preparation of the installation of a CAN (as well as for a suction anchor) a geotechnical assessment of the seabed in which it is to be installed has to be performed. The main results of this assessment are to determine the minimum dimensions of the CAN to achieve the required load capacity for the well and also to verify that the required suction pressure is within the structural capacity limits of the CAN. The most critical parameters for these calculations are the undrained shear strength and the clay sensitivity. The first parameter is determined by the cone penetration test (CPT), the latter is only available by analysing core samples, however these are rarely available for exploration or appraisal wells. The literature gives a range of values for this parameter, which is selected conservatively and define the lower and upper bound cases. Preparation of Input Parameters The available CPT locations for the well Wisting Central II were unfortunately quite far from the spud location and showed a great deal of variations. Fig. 4 shows an overview map over the Wisting area with wells (drilled as well as planned) and CPT tests taken. With reference to Fig. 4 and Fig. 5 the input data can be evaluated as followed: · CPT 10 is the closest test set located about 2.8 km east-north-east from the spud location and shows favourable soil conditions with an S­u around 50 kPa at 10 m depth. · CPT 03 is located about 3.5 km north from the spud location and shows an increased strength formation coming in at 2 to 3 m below mudline. This would stop the CAN penetration quite quickly if present at the installation location. The height of the structure would have to be adjusted to cope with this special soil condition · CPT 09 is located about 4.6 km east of the spud location and shows favourable soil conditions with an S­u slightly below 50 kPa at 10 m depth similar to CPT 10 · CPT 06 is located about 5.3 km north of the spud location and shows an increased strength formation coming on at around 12 m below mudline · CPT 04 is located about 6.5 km north-north-west of the spud location shows a moderately increasing strength formation coming in at around 2 m below mudline Evaluating all the data above results in the uncertainty about the depth of the increased strength formation in the north-western area (later addressed as Unit II). Therefore a geotechnical correlation based on shallow seismic was undertaken to assess whether this layer is relevant for the geotechnical assessment. In addition two scenarios where such a consolidated layer comes in were investigated: · Unit II coming in at 8 m below mudline · Unit II coming in at 6 m below mudline Figure 4 – Overview map Wisting area (well and CPT locations). Figure 5 – CPT results for Wisting area. Geotechnical Correlation This correlation was done by a 3rd party provider, so only the results are mentioned in this work. Fig. 6 indicates the presence of a horizon at a depth of 27 m, which represents the border between Unit I and unit II. Based on this information and a CAN height of 7.5 to 11 m it could be concluded that this hard layer would not be a challenge for the installation. The second part of the correlation was to derive the input parameters at the spud location based on the reference wells which concluded as shown in Table 1. Unit Depth Sensitivity Unit Weight Undrained Shear Strength [m] [] [kN/m3] [kPa] Unit I 0.0 1.75 8.0 6.0 27.0 1.50 8.0 90.0 Table 1 – Shear strength profile. Figure 6 – 2DHR seismic line section - Wisting Central II. CAN Dimensions and Load Capacity Assessment As the well to be drilled was an appraisal well, the CAN well foundation was to be rented for the duration of the well. The available rental units are of 6 m diameter and were in stock in different heights ranging from 7.5 m to 11 m. As a first step the load capacities of the shortest and the longest available unit were determined, these are given in Table 2 and can be summarized as followed: · Base case short (7.5 m) Unfactored load capacities of this scenario are close to the design load, therefore no sufficient load capacity was reached. · Base case long (11m) Unfactored load capacities of this scenario are in excess of the double compared to the design load, allowing for a safety factor > 2. Based on the above results the CAN unit of 11 m height was selected. Fig. 7 shows the penetration resistance and underpressure calculation. At full penetration the resulting under pressure was predicted to be 2.9 bar. Fig. 8 shows the overturning capacity. It has to be noted that the design load (red line) is depending on the penetration depth (resulting moment arm) of the well foundation. The deeper the unit is penetrated the less moment arm which results in a decreased moment Table 2 – Load capacities for CAN (unfactored). Figure 7 – Installation assessment (base case), penetration resistance and critical suction. Figure 8 – Installation assessment (base case), overturning moment capacity (H applied at CAN top). Backup Scenarios As mentioned above two additional scenarios were investigated to mitigate any risk connected to an unidentified increase in shear strength similar to Unit II. Fig. 9 shows the shear strength profiles that were assumed for the two scenarios. Of particular interest was the overturning capacity for the case that the CAN penetration would meet premature refusal due to excessive suction pressure, as caused by an unforeseen higher soil shear strength. Therefore the allowable suction pressure was limited to 3.5 bar although the structure is rated for 10 bar under pressure. The resulting maximum penetration as well as overturning moment for lower and upper bound assumptions are as followed: · 6 m (Lower Bound) o 3.5 bar under pressure is reached at 7.2 m penetration o Resulting minimum overturning moment is 13 950 kNm · 6 m (Upper Bound) o 3.5 bar under pressure is reached at 6.6 m penetration o Resulting minimum overturning moment is 13 322 kNm With a design load of maximum 6 000 kNm and early refusal at 6.6 m the CAN would still be able to deliver the required capacity with a safety factor of 2.22. The detailed load capacities for both cases are given in Table 2. Figure 9 – Undrained shear strength profiles for 6 m and 8 m layer. CAN Operations Installation The CAN was installed at the well location in December 2014 (Fig. 3 shows the deployment through the splash zone). The ROV video survey of the seabed showed a significantly sloping seabed. After initial penetration to fix and check the location and orientation of the CAN, it was identified that the slope of the seabed caused a significant CAN inclination from vertical (3.3°). In the further process the CAN was partially lifted out of the seabed to allow gravity to correct the inclination. This reduced the tilt, but active measures had to be taken to bring the CAN back to vertical. This was achieved by moving the installation vessel surface locaton a certain distance into the opposite direction of the CAN tilt, reducing the inclination to 0.6° from vertical, which is within the acceptance criteria of 1.0°. This number improved further to a final inclination of 0.18°. Fig. 10 and Fig. 11 show the CAN fully penetrated and visualizes the slope in the seabed. Fig. 10 represents the low side with a 0.9 m distance from the top of the structure to the seabed level (each depth indication represents 10 cm). Fig. 11 (right hand side beyond the lifting pads) shows the high side. In total the installation parameters can be summarized as followed: · Verticality: o Target <1.00° o As installed 0.18° § Pitch 0.11° § Roll 0.14° · Penetration: o Target 10.70 m o As installed (high side) 11.00 m (full penetration) o Comment: Significant seabed slope encountered, 90 cm over the diameter of the CAN, equivalent to 8.53° or 15 %. · Position: o Target North (± 50 m) 8 152 829.42 m o Target East (± 50 m) 603 693.34 m o As installed North 8 152 831.00 m (+ 1.38 m) o As installed East 603 695.00 m (+ 1.65 m) · Orientation: o Target 180.00° o As installed 171.30° Figure 10 – Final penetration (low side). Figure 11 – Final penetration (high side). Geotechnical Back-Calculation After completing the installation, the recorded data were used to update the geotechnical model to determine the actual "as installed" load capacities of the CAN. It is important to note that this is a unique feature of this type of well foundation. No other conductor installation method allows such an exact load capacity verification. The back-calculation uses the actually measured underpressure versus depth curve to match the soil parameters at the installation location. This was especially important for this case as the input parameters for the spud location had to be extrapolated from CPT data with several km distance. Fig. 12 shows the match between measured (onsite data) and corrected (back-calculated suction) after the model update. The remaining deviations can be explained as followed: · Depth range 2 – 5 m: There was an operations delay in the beginning of the installation to correct the inclination. This possibly caused short term set-up effects which resulted in slightly higher values. · Depth range > 10 m: Due to the sloping seabed the CAN lid came in contact with the seabed at around 10 m penetration, causing an increase in penetration resistance. The resulting load capacities are summarized in Table 2. The differences in under pressure and load capacity is explained by the different bearing mechanisms: · Prediction: skirt friction inside and outside (ceiling of structure not in contact with seabed) · Actual: skirt friction outside and end bearing (ceiling of structure in contact with seabed) Figure 12 – Updated suction pressure based on measured data. Drilling Phase One of the two main objectives of the appraisal well Wisting Central II was to prove that it is possible to penetrate such a shallow reservoir horizontally. This is one of the requirements to economically develop these resources. The well was drilled as planned, and already in the 20 in. surface casing section it proved possible to build slightly more angle than planned for. The initial goal with the 26 in. BHA was to kick off from vertical and if possible build 1 to 2° of inclination. This was successfully executed and resulted in an inclination of 2.5° at 50 m below mudline. Fig. 13 shows the whole trajectory for the well including the 1.4 km horizontal section. Besides proving the feasibility of the very shallow kick off, this installation also demonstrated the fact that shallow set conductors (e.g., 10 m penetration) will suffice for continued drilling below the CAN. There were no signs of borehole instability or washouts when drilling the 26 in. hole for the 20 in. surface casing or flow broaching on the outside of the CAN structure. Another crucial benefit for the operator was to have the conductor capacity and inclination verified prior to rig arrival. Out of five available reference wells in the area, three had a conductor inclination (before cementing) of more than 1.5° (specified limit of the drilling contractor). Even though the inclination could be reduced by keeping the conductor in tension until the cement was set (up to 15 hours), this causes additional rig time. As referenced above, the CAN integrated conductor could be installed at an inclination of 0.18° only. Even though the load capacity of the well foundation was undisputed, daily checks of the bulls-eye mounted on CAN were performed for documentation (see Fig. 14). No movements of the CAN were detected during the whole project, which included the drilling and production test program of more than 70 BOP days. The installation of the conductor by vessel also has other beneficial effects with respect to cost and safety: · The well positioning is done on vessel rather than on rig day rate and less personnel needs to be mobilized to the rig. · There is no handling of heavy 36 in. conductor and handling equipment on the supply vessel or on board the rig. This reduces HSE risks for personnel and frees deck space on the vessel and rig. · The maximum BHA size is reduced from 42 in. to 26 in. Again this reduces HSE risks for personnel and frees deck space on the rig. · The cement job for the conductor is avoided, saving rig time and cost for materials and chemicals. The conductor cement job is usually the second largest cement job in terms of consumables (cement, chemicals, etc.). · No guide base is necessary, as guide posts are directly integrated into the CAN. This saves cost and reduces HSE risks for personnel by reducing the handing of large and heavy structures through the rig's moonpool. · Casing cutting risk mitigation: The integrated conductor allows to simplify the cutting of the casing strings (see Fig. 15). Conventionally the 20 in. casing, cement and the 36 in. casing have to be cut. As shown in Fig. 15 the volume to be cut for the conventional method (left hand side) is substantial larger compared to cutting the 20 in. casing only (right hand side). When the cutting operation goes as planned the tie saving would be less significant, possibly about one hour. However, often circumstances like cutter arms braking, premature cutter wear and/or eccentrically casing strings may require a second cutting run, which would easily cause additional 8-12 hours rig time. · Installation of the CAN can be done independent of the rig schedule, preferably in the good weather period to de-risk well spud operations with the rig in bad weather seasons. Figure 13 – Well trajectory of well Wisting Central II. Figure 14 – Bulls eye on CAN. Figure 15 – Simplification of casing cutting operation. Results and Conclusions All goals set for this appraisal well were achieved as planned, which now represents the shallowest horizontal well drilled from a floating drilling unit to date. The enabling factor was to combine existing technologies in a new way as described by Hollinger (2017). One of the key elements creating confidence in achieving the high dog leg trajectory was the integration of the conductor into the CAN well foundation. This allowed to shorten the conductor from minimum four joints to only one joint, increasing the available TVD for building inclination by more than 10%. Despite the challenges with respect to the missing CPT data at the spud location it was possible to select a fit for purpose CAN design that was installed without any incidents and also delivered the required load and performance capacities as planned. The CAN was not only one of the technologies that increased the likelihood of success to deliver the planned well trajectory, but also managed to contribute to net cost savings. Cost Savings The operating company reported an average conductor setting time of 3.0 days for the Wisting area. This somewhat higher number than the industry standard is related to the circumstance that for 3 out of 5 wells the conductor had an inclination of more than 1.5° before cementing it in place. To correct this the conductor had to be kept in tension until the cement had set completely. It was stated by OMV that 60 % of the rig cost savings were used on the CAN system (rental of equipment, installation and recovery vessel and logistics, etc.). This results in a net saving of 40 %, or 1.2 rig days. In detail the savings include but are not limited to: · Equipment and services not required when using the CAN with pre-installed conductor: o 3-5 conductor joints (depending on soil conditions) o Conductor running tools and services o BHA including bits, stabilizers and hole opener o Cement job for conductor o Stinger, cement plugs and other equipment · Guide base · P&A time savings and risk mitigation (as mentioned above) · Risk reduction (possible NPT (non-productive time)) linked to above equipment and operations Further Developments, Optimization Possibilities Even though the Wisting Central II well was an undisputable planning and operational success, options for further improvement and risk reduction are to be assessed. The applied casing program was the conventional combination of 36 in. conductor, 20 in. surface casing, 13 3/8 in. intermediate casing, etc. Based on the successful Wisting II well it is projected that the well architecture can be simplified by omitting casing sizes, thus allowing a further significant reduction of the cost of tubulars required for the well construction. Besides the fact that the reduction of casing sizes can be commercially attractive if the completion strategy allows for this, smaller casing sizes might also be beneficial to be run in higher dogleg environments. The CAN technology will allow reducing the casing sizes substantially, as the conductor loads are reduced to a few percent as soon as it is supported by the CAN. Figure 16Fig. 16 shows the bending moment along riser, BOP and conductor for both cases, for a conventional conductor (red line) and a CAN integrated conductor (green line). It is clearly visible that the bending moment drops dramatically as soon as the CAN supports the conductor (green area). This allows to reduce the casing diameters for the conductor and all subsequent casing strings, which again allows to increase the dogleg to reach even shallower reservoirs. Furthermore, it is possible to integrate the kick-off point into the conductor (also shown in Fig. 17). To kick-off the well from vertical is a critical operation, it is important to attain the planned azimuth when initiating the deviation. By integrating the kick-off point into the CAN well foundation it is possible to attain immediate control of the kick-off direction. Figure 16 – Bending moment along riser, BOP and conductor. Figure 17 – CAN with integrated slender conductor. Nomenclature Abbreviations CAN Conductor Anchor Node CPT Cone Penetration Test HPWHH High Pressure Wellhead Housing LPWHH Low Pressure Wellhead Housing NPT None-Productive Time NCS Norwegian Continental Shelf ROV Remote Operated Vehicle Symbols St Clay sensitivity Su Undrained shear strength

The CAN-ductor used for the Dugong Tail well was recovered January 1st 2022. The recovery operation, from vessel arrival in the field until the CAN-ductor was on deck took about 24 hours. The operations was successful and carried out according to plan.

The two Lundin exploration wells Bask and Polmak, drilled with the West Bolstad rig in the same area in the Barents Sea in 2020, were compared against each other. The Polmark well had been established with conventional drilling and a cemented conductor whilst the Bask well utilised a pre-installed CAN-ductor. The total environmental impact for each well was assessed and compared by one of Norway’s leading environmental consulting firms Asplan Viak. The study documented a total reduction equivalent of 420 tonnes CO2 with the use of a CAN-ductor, a reduction of 45%. 1. Methodology The environmental impact of both wells was measured using life cycle assessment (LCA). LCA is a systematic method which aims to evaluate the environmental impact of a product or service through its life cycle; from extraction of virgin material, production, transport, use phase and waste management. According to the European commission it is the best available framework to assess the environmental burden of a product (Hellweg and Milà i Canals, 2014). An LCA study may consider several environmental impact categories, such as climate change, human toxicity, particulate matter formation, terrestrial acidification, freshwater eutrophication and marine eutrophication. LCA consists of four phases: 1 – goal and scope, 2 – inventory analysis, 3— Impact assessment and 4 – interpretation, which are illustrated in Figure 1 and described below. Figure 1 - The four phases of a Life Cycle Assessment The inventory analysis modelling and impact calculation (see figure 1) in this study was conducted with SimaPro software 2. SimaPro is the most used software for LCA worldwide and allows for continuous and subsequent revisions and investigations. In an LCA study, it is typical to distinguish between foreground and background data. The foreground data is collected for a specific study and describes the system in question, while the background data is generic data from a database. The foreground data in this study was based on information provided by Lundin Energy Norway (LENO) and Neodrill, while the background data was based on inputs from the ecoinvent database, and a pre-existing database of offshore oil and gas operations developed by Asplan Viak. The ecoinvent database was developed and is maintained by the Swiss Centre for Life Cycle Inventories. The database is constantly expanding and is to date the World’s most extensive database for conducting LCAs, containing nearly 15 000 datasets in areas such as energy supply, transport and fuels, chemicals, construction materials, wood, and waste treatment. The study is based on well geometry data and descriptions for the well sections as provided by LENO and Neodrill. The model includes inputs for scenarios describing the conventional conductor and the CAN-ductor technology. As the CAN-ductor affects the requirements related to the subsequent 26" well section, the study examines this well section to some degree. The input for the analysis is based on delta values, meaning that the environmental impacts do not cover the total impacts of the drilling operations for the wells. The data inputs include the offshore drilling unit, supply vessels, energy, casing materials, and the production, installation, removal, and maintenance operations of the CAN-ductor unit. Figure 2 illustrates the considered wells architecture and input data tables for conventional and CAN-ductor technologies. The rig time for the conventional conductor is higher due to the top-hole drilling activities and conductor cutting and removal activities. With the CAN-ductor there is a high diesel fuel consumption related to transport and mobilization of the CAN. The Bask well has rig time related to an increase in 26" hole section drilling activities. Figure 2 - Well architecture with input data from conventional conductor and CAN-ductor 2. Conventional drilling verses CAN-ductor technology For the conventional conductor on the Polmak well, spudding consisted of drilling the 42" x 36" hole section and installing a 67 m 36" x 30" conductor. The 50 tonnes of casing was transported from Hammerfest to the Polmak well by LNG supply ship and is accounted for in the life cycle model. Installation of the conductor amounted to 66 hours of operation on the West Bolstad rig. The process involved seawater and water-based mud being pumped into the well to transport cuttings out of the well, cool and lubricate the drill bit, stabilize the formation, and maintain down-hole pressure. Cuttings and drilling fluid are deposited to the seabed. Thereafter, the annulus between the open hole and the conductor are filled with cement. Some of the cement is discarded on the seabed. Before the well is abandoned, the conductor will be cut and partially removed, which requires a rig time of 16,7 hours. Figure 3 provides an overview of the system processes related to the modelling of the Polmak well. Drilling time (West Bolstad) includes all activities related to activities when installing a conventional conductor. The well casing profile includes all activities and impacts from the casing itself, and offshore discharge includes all impacts from discharges of cuttings, drilling fluids and cement. Figure 3 - Overview of system processes in the LCA model of Polmak The CAN-ductor is a pre-installed and re-usable well foundation that is installed by suction anchor, prior to the arrival of the drilling rig. The CAN is lowered to the seabed using its own weight to plant itself on the sea floor. An ROV creates an under pressure in the CAN by sucking water out of it, making the CAN penetrate deeper into the seabed. Figure 4 - CAN lowered to the sea floor by support vessel and penetrates the seabed by ROV The CAN-ductor removes the need for top hole drilling, conductor installation, and the use of drilling fluid, thereby avoiding disposal of cuttings, subsequent leaching of heavy metals, and discharge of drilling fluids on the seabed. The weight of the CAN-ductor unit installed on the Bask exploration well is 116 tonnes - 106 tonnes of steel and 10 tonnes of concrete. The manufacturing and maintenance processes of the CAN-ductor are included in the life cycle model. The CAN unit was transported to the offshore location by the marine diesel fueled installation vessel, Island Victory. In order to keep the assumptions for conventional conductor casing and CAN on the same level, the transport from Stavanger to Hammerfest have been disregarded in this study, as the detailed transportation of conventional casing is not available and the differences in environmental impact are negligible. It is assumed in the study that the CAN unit is used on one well before being transported back to shore for maintenance. Maintenance of CAN-ductors takes place in Stavanger and includes equipment washing after every use, repainting every second use, and targeted welding after being used on five uses. The expected lifetime of a CAN-ductor is ten wells. The Bask well was ascribed 10 % of the impacts associated with production and maintenance of the CAN-ductor unit. The first hole section drilled on the Bask CAN-ductor well was the 26"section. As this section on the well required more work compared to the Polmak well, 3 hours of rigtime was added to its life cycle modelling. There was also an added volume of cuttings with residue of water-based mud, based on the 53 meters of additional drilling length on the 26"section. Although CAN facilitated riser-less mud recovery systems (RMR), there remained a slight mud residue on the cuttings discharged to the sea floor. It is assumed that the 26"well section had a disposal rate of 0,34 m3/m (theoretical factor) resulting in 20 m3 added cuttings. The CAN-ductor eliminates the need of cement in the top hole, however 15 m3 of additional cement was required as the CAN-ductor was 53 m shorter than the conventional conductor. Figure 5 provides an overall overview of the system processes relating to the modelling of the Bask well. West Bollsta represents all extra drilling activities connected to the 26"hole section on Bask. The CAN manufacture, maintenance, and installation processes include all activities related to the CAN itself. All discharges to sea occur due to the increased activity on the 26" hole section and are represented under offshore discharge processes. Figure 5 - Overview of system processes in the LCA model of Bask 3. Impact Assessment Result The compared environmental impacts of the conventional conductor (Polmak) and the CAN-ductor (Bask) well are presented in Table 1. Table 1 - Compared environmental impacts for the Polmak and Bask wells Figure 6 - Contribution analysis for delta values of conventional VS. CAN-ductor well impacts The CAN-ductor well has lower impacts associated with drilling time and the well casing compared to the conventional well. While the CAN- ductor well had additional impacts associated with production, installation and removal and maintenance, the re-usability resulted in lower impacts compared to the conventionally drilled well. For the conventional conductor technology, drilling time and well casing were responsible for around 90 % of the impact in several categories, including climate change, while discharges to sea were responsible for the remainder. 4. Conclusion The goal of this LCA study was to quantify the difference in environmental impacts associated with the conventional conductor technology used on the Polmak well and the CAN-ductor technology used on the Bask well. The CAN-ductor drilling well had lower environmental impacts compared to the conventional conductor, especially for the climate change category. The reduced environmental impacts can be mainly attributed to lower rig time and fewer well casing materials. The reduction in CO2-equivalents amounted to 420 tonnes. The CAN-ductor required transport and handling by a diesel driven vessel, as opposed to the conventional equipment which is transported by an LNG carrier. Replacing this diesel driven vessel with an LNG carrier in the model, substantially reduce the emissions of SOx,NOx and greenhouse gases. In addition to the quantified benefits in the LCA analysis, the CAN-ductor offers further environmental benefits and advantages. This includes cuttings reductions which subsequently reduce the disturbance of benthic ecosystems that are sensitive to the turbulence by cutting disposal to the seabed. Furthermore, the CAN-ductor well drilling technology offers advantages with respect to cost, use of tool and special equipment, cement service crew, logistics, transport, and HSE aspects. In conclusion, the use of the CAN-ductor technology offers several environmental benefits and advantages compared to the conventional conductor technology. 5. References Baumann, H. and Tillmann, A.-M. (2004) The Hitch Hiker’s Guide to LCA. Lund,Sweden: Studentlitteratur. Hellweg, S. and Milà i Canals, L. (2014) ‘Emerging approaches, challenges and opportunities in life cycle assessment.’, Science (New York, N.Y.), 344(6188), pp. 1109–13. doi: 10.1126/science.1248361. Rebitzer, G. et al. (2004)‘Life cycle assessment Part 1: Framework, goal and scope definition, inventory analysis, and applications’, Environment International, 30(5), pp. 701–720. doi: 10.1016/j.envint.2003.11.005. Asplan Viak Rapport 630444-01-Comperative LCA of the Neodrill CAN-ductor technology

As we’ve now passed the halfway point of 2021, I wanted to share a roundup of all our news from the year so far. As we approach Q3, it has been a busy and productive year to date with new contracts, manufacturing projects, positive LCA reports, CAN recoveries, development of new technologies, partnerships, and new additions to the team. Contracts Back in Q1 we announced a frame agreement with Lundin Energy for the utilisation of CAN technologies on their wells. This exciting news signals a continued recognition of the significant benefits of CAN technologies to reduce rig time, cost and CO2 emissions associated with rig led top-hole operations. We look forward to delivering the latest CAN-ductors under this agreement later in the year. CO2 reduction More recently we announced an update on the environmental results of our existing CAN technologies utilised by Lundin on their Bask subsea exploration well in the Barents Sea. The latest Environmental LCA Reports, conducted by Asplan Viak AS, confirmed a 45% (420 tonnes) reduction in CO2 emissions from CAN-ductor use compared to a conventional conductor installed by a rig on the neighbouring Polmark well. Further LCA reports demonstrating the potential to reduce environmental impacts are available via our website. In support of our goal to promote decarbonisation in the industry, we were also proud to launch our ‘do what you CAN’ campaign which featured on DN.NO earlier in the year. Manufacturing This deal activity and delivery of CO2 emission cutting CAN-ductors to our clients means that product manufacturing has been central to our operations this year. We have so far been manufacturing 3 new CANs at our manufacturing site in Norway - Randaberg industries. These are expected to enter service later this summer for a new contract that we look forward to announcing soon. CAN-complete - recovery Further hands-on work included the deployment of our CAN-complete service, together with Ross Offshore, to achieve a key recovery operation. The recovery of the CAN-ductor on the Bask Well in the Barents Sea saw the end of Lundin’s drilling operations on the well which was a successful CAN-ductor deployment and significant measurable reductions in CO2 emissions. Partnerships In recognition of the value of our cooperation with Ross Offshore, we also recently announced a continuation of our partnership to secure the incorporation of their marine and charter services into the CAN-complete package for the long term. The cooperation will reduce costs for clients through streamlined operations from CAN orders to top-hole establishment. Similarly, we have committed to a continued collaboration with Baker Hughes on the integration of CAN technologies with Baker Hughes’ Terminator Tool for P&A operations. Integrating this tool within the CAN top-hole solutions can significantly reduce emissions and cut rig time by up to 12 hours. New team members Closer to home we’ve also been growing, with the addition of our new Senior Engineer, Anders Selvåg, to the team. Anders holds an MSc in Underwater Technology from the Norwegian University of Science and Technology and has more than 7 years of experience in marine operations within the oil and gas sector. Here at Neodrill he will play a key role in our research and development programme and will support business development activity. Research and Development This research and development programme has particularly focused on the development of the Wellhead Saver System (WSS) for application on P&A operations. At Neodrill we have a strong history of invention and innovation dating back to the early development of CAN technologies more than 20 years ago. This year has seen that innovative spirit applied to the extension of WSS capabilities to meet the growing P&A focus in the UK sector. Alongside this, we continue to explore further solutions to improve well longevity, costs, safety, and environmental footprint. Looking ahead to the rest of the year With this continued development of all aspects of our business, the first half of the year has been a busy, successful, and inspiring period. As the year goes on, we will continue to innovate, build relationships, and provide industry leading top-hole solutions to clients who seek to revolutionise their operations. I look forward to seeing what the rest of the year brings as our projects come to life. Interested in learning more about Neodrill’s products, services, and activities? Get in touch for more information.