Vår Energi's ambition is to accelerate well planning maturation while sustaining consistently top-quartile execution performance, from initiation through to a drill-ready well. Achieving that has demanded more than a new piece of software. It has required a shift in how subsurface, subsea, and project development, and drilling and wells business units work together.
Rather than maturing a well trajectory through a sequence of discipline-by-discipline handoffs, the three teams now plan inside a shared, real-time environment, jointly maturing the same trajectory from the first sketch through to a drill-ready design. The intent is to plan faster and use that speed to test more of the design space per well and capture more value.
One Environment, Multiple Domains
The scope of the new shared environment is wide. On the subsea and site side, it covers infrastructure constraints, bathymetry, and shallow-hazard mapping, including pock marks, anchor scours, boulders, and shallow gas, alongside surface-location placement. On the subsurface side, it covers reservoir well placement and risk factors, such as pore pressure, shear failure gradient, and fracture gradient, that shape a safe design. On the drilling side, it covers drilling-corridor definition and wellbore-geometry optimization.
Historically, each of those was effectively someone else's problem until a trajectory was far enough along to hand off. In the shared environment, all three are visible to everyone from the first sketch of a well (Fig. 1), which is what makes it possible to optimize reservoir exposure and design robustness together rather than resolving them one after another.
The new environment is also not a single piece of software running in one place. Some of the applications it connects run on premises while others run in the cloud. Making that combination feel like one workflow took a purpose-built, synced-drive IT integration layer to bridge the two. This is a deliberately fit-for-purpose piece of infrastructure, assembled around what the team already had, rather than a single platform bought off the shelf to replace it.
A Sequential Process Built for a Different Era
Well planning within the operator was typical of the industry and had been organized as a sequence of discrete steps: data preparation, drafting a trajectory, a pore-pressure/fracture-gradient plot and shallow-hazards check, picking formation tops, well engineering, and a design reassessment before the cycle could close. Data preparation alone typically took 25 to 30 days, drawing on inputs from all three domains in turn.
Each later step added 1 to 3 more days on its own, but if the reassessment surfaced a conflict, a target that didn't clear a wellbore-stability check, or a trajectory that fought with a subsea infrastructure or shallow-hazard constraint, the sequence looped back to drafting a new trajectory. That loop could add another 30 to 40 days, with the same six to eight people redoing analysis they had already done once (Fig. 2).
None of this was a failure of any one team. It reflected three domains, each with its own data and review cadence, feeding into a well trajectory sequentially rather than jointly. That pattern does not hold up against a portfolio of smaller, faster-moving opportunities, where the planning cycle itself becomes the constraint on how many wells a team can properly evaluate.
Surface-location placement was a clear illustration of the cost. Getting a location right depends on subsea infrastructure and pipeline routing, bathymetry, and site-survey and shallow-hazard data on one side, and subsurface targets and drilling constraints on the other.
That information lived in different systems, owned by different teams, and reconciling it by hand routinely took weeks per option. Evaluating two or three location alternatives, which is normal for anything but the simplest well, could consume a large share of a project's early planning schedule before a single foot of hole was designed.
From Handoffs to Shared Understanding
In the shared environment, the sequence collapses into something closer to a single conversation. As a trajectory is planned and edited, drilling windows and well design update live, with formation tops and hazard data linked directly to the subsurface model. A shallow-hazard risk or a subsea infrastructure limit is visible to the well planner.
Now a trajectory is drawn versus surfacing such issues in a review weeks later. Subsurface targets and risk factors are, in turn, understood by the wider team from the outset, rather than explained after the fact once a trajectory conflicts with them.
That also changed what a planning meeting looks like. Instead of three domains arriving with three separate views of a well and spending the first part of a meeting reconciling whose numbers were current, everyone works from the same model.
Disagreements that surface now tend to be genuine technical tradeoffs, such as how much risk to accept on a tighter drilling corridor in exchange for a better tie-in distance. This avoids arguments caused by someone working from data that was already out of date.
That does not mean every hour of work happens inside the shared model. A typical trajectory goes through five to 10 joint sessions. Each session puts the right people in front of the right data to make the decisions that need everyone in the room.
These discussions include where a target sits, whether a hazard rules out a corridor, and how a tradeoff gets resolved. Between sessions, each discipline returns to its own detailed work and comes back with updated input for the next one. The shared model is where alignment happens, but it is not where every hour of analysis gets done.
Optimizing Both, Not One
The payoff is fewer conflicts and lower risks, but it also yields opportunity. With subsea and geohazard constraints visible from the outset and subsurface risk understood by the wider team, a trajectory can be derisked and optimized for reservoir exposure at the same time.
In practice, this has meant looking for the combination of trajectory optimization and reservoir exposure that maximizes value from a single well. In the past, the process may have treated the two as a tradeoff where one is optimized at the expense of the other.
A wellbore geometry that would once have been set conservatively, simply because all the constraints were not understood early enough to test alternatives, can now be pushed toward more reservoir contact once the team can see that doing so doesn't compromise what matters.
The same real-time visibility has started to make CO2 a live design variable. An integrated CO2-footprint estimate covering well design and drilling-fluid selection lets the team compare the emissions profile of trajectory and design alternatives alongside cost and risk. In the past, a CO2 estimate would be made after the design was already fixed.
Results After 1 Year In
A faster, joint process invites an obvious question: does it hold up to the same scrutiny as the one it replaced? The technical standards and sign-off requirements have not changed. What has changed is what reviewers are looking at. The reconciliation work has already happened inside the shared model, so review time goes into engineering judgment.
The results, after about 1 year of deployment, are field-tested. Concept maturation on wells planned through the shared environment has dropped from a typical 6 to 8 weeks down to 1 to 2 days.
A 7,000 m extended-reach drilling feasibility assessment that would previously have taken multiple weeks of iterative handoffs between subsurface targeting, trajectory design, and geomechanical review was completed in 3 hours.
More than 20 well concepts have been screened, each in a matter of days, compared with about a week or more per concept under the previous process. The same six-to-eight-person group that used to need 30 to 40 days to close a full design cycle, including a reassessment loop, now requires only 1 to 2 days. The full well maturation process on these projects that once took weeks to months is now routinely achieved in days.
The Learning Curve
The new process was built as a continuous learning loop, and the team treats that as an advantaged feature. What exists today is closer to an 80% solution, and that 80% has already produced the results listed above. We view this as proof that most of the old process's cost was friction. The goal was not to spend years perfecting the platform in order to allow the team to capture value as early as possible. Every project since the first is being used to sharpen the model further, each cycle feeding lessons learned into the next.
Closing the remaining gap is as much a people question as a technical one. Those who experienced the old process have described the relationship between disciplines as a you-and-us culture that resulted in tough meetings, hard arguments, and a struggle to align.
That is exactly the dynamic the shared model was built to dissolve. As the improvement compounds over time, each new project brings its own lessons back into the loop, and both the model and the working relationships around it get measurably better as a result.
Scaling With Conviction
One of the most telling figures involves the rate of adoption. Five projects were running on the shared environment in parallel within 6 months of the first proof of value which was backed by senior sponsors across subsurface, subsea, and project development, and drilling and wells business units. The new process was pulled forward by teams asking to join once they saw what the first project had produced. Furthermore, the approach held up under real project pressure and strict deadlines, and it earned support from the people doing the work as well as those leading it.
The internal backing shaped how the approach was scaled. The company departed from a single mandated onboarding schedule as senior leaders across disciplines cleared the way while later projects joined as their own teams requested it, with the original project group acting as informal references for what to expect.
Leadership support removing obstacles, and adoption pace tracking demonstrated value which allowed five projects to achieve scale in 6 months without either forcing the pace or leaving it to chance.
None of this depended on capability that didn't already exist elsewhere in the industry. The digital environment matters, but it is considered only the enabler. What unlocks the value is the integrated team behind it, and the mindset shift that comes with working jointly. This enables operators to move past time-consuming handoffs and into a collaborative effort to plan the trajectory together from the beginning. This results in a process and behavior change more than a procurement decision.
Looking Ahead
The handoff bottleneck the new process addressed is not unique to the operator in this case study or others working in the Norwegian Continental Shelf. Most operators managing infill and marginal-field portfolios have some version of the same sequential structure.
The specific technology used matters less than the process that it enables which is to replace a static handoff system with one that works in a real-time environment and then allowing adoption to spread based on demonstrated results.
Within the operator, the next step involves extending the same integrated approach earlier, into the field-development-concept stage that precedes individual well planning, so all three domains are working jointly before a specific well is on the table.
None of this required abandoning existing tools or any domain's way of working. But it did require connecting them. More importantly, it required changing how the people behind them expected to work together. For an industry increasingly defined by smaller, more marginal opportunities and shorter decision windows, that may be a more replicable lesson than any single piece of technology. One of the operator’s biggest lessons was that real value came from creating a multidisciplinary team that jointly optimizes reservoir exposure together from the first sketch of a well.
Brede M. Tøllefsen is the vice president of drilling and wells engineering at Vår Energi, with more than 15 years of international experience in well engineering, project delivery, and leadership across offshore Norway, the Middle East, and West Africa. He has held senior leadership positions at Vår Energi, Neptune Energy, Shell, and New Subsea Technology, delivering complex drilling and well projects from concept selection through execution. He is passionate about operational excellence, technology adoption, and building high-performing teams that deliver safe, efficient, and value-driven energy projects. Tøllefsen holds an MSc in petroleum engineering from the Norwegian University of Science and Technology and an MBA from Bradford University School of Management.
Siddhartha Lunkad is the drilling and wells improvement manager at Vår Energi, with 19 years of international experience in drilling and wells engineering, offshore operations, well integrity, and digital transformation across Norway, Qatar, the US, and India. He has led the digital agenda across Vår Energi's drilling and wells department. He is passionate about digital innovation, cross-discipline collaboration, and building integrated ways of working that make well delivery faster and more robust. Lunkad holds an MS in chemical engineering from the Indian Institute of Technology, New Delhi.