When Statoil took a close look at development costs a few years ago, it was apparent that things needed to change.
According to Torger Rød, Statoil senior vice president for project development, even before the drop in oil prices, the Norwegian operator realized costs were too high. “We started the improvement program in 2015, focusing first and foremost on what Statoil can really influence,” he said.
In examining what truly was within Statoil’s power to change, the company examined total value creation and identified five critical ingredients for improvement. The result, he said, is a “recipe” the company has been tweaking ever since.
Statoil began with the acknowledgement that, “not only do we have to do better, but we can do better,” Rød said. This recognition led to setting direction and specific targets, such as cost reductions and clear breakeven objectives, with an eye to where the company would like its portfolio to be.
Next was a focus on engagement, which meant bringing the team together so the company could strive cooperatively toward the same goal.
“There are very competent people in Statoil,” Rød said. “When we are able to ensure we are getting great engagement and good collaboration through the value chain, you see creativity and start to develop very efficient concepts.”
The fourth ingredient is what Rød calls “totality,” which means making sure the entire concept makes sense so the greatest gains can be achieved. “We have to avoid a suboptimal solution. This is about creating value. This is about reservoir drainage and efficiency,” he added.
The final piece, he said, is collaboration, both within the company and with service providers, contractors and partners.
One of the first things to come under scrutiny was the assets being built and where they would be operating, Rød noted. “We started approaching our prospects and projects to optimize our concepts,” he said, and that led to considering a range of ways to develop offshore prospects.
In the case of the Johan Castberg Field in the Barents Sea, Statoil changed the design concept, moving to develop the field with a FPSO. This allowed the company to optimize the field layout, reducing the number of wells from 43 to 30 and the number of subsea templates from 15 to 10.
“We started working together with subsea contractors to look at the subsea production system,” Rød said, “setting clear cost targets and recognizing that changing the subsea system would allow Statoil to achieve that goal.”
Decreasing complexity was part of the solution, but there was much more involved. By reducing companyspecific requirements, Statoil enabled subsea experts on the contractor’s team to introduce efficiencies. In the end, the tree and manifold weight were lowered significantly, and the footprint was reduced by 45%. “We removed 10% to 20% of the weight,” he explained, “and less steel means less money.”
The Snorre Expansion project is another in which working closely with partners and suppliers led to greater profitability. In this case, what began as a marginal project became a worthwhile development as a result of collaboration aimed at finding ways to optimize value creation and reduce total cost of ownership. “We are testing ideas on one another,” Rød said, “and when we see a program doesn’t have value, we stop pursuing it.”
The subsea layout using bundled infield flowlines on the Snøhvit Expansion project is a good example of how Statoil followed the lead of one of its contractors. “Subsea 7 proposed this,” he said, noting that it has been many years since Statoil used such a layout. “We assessed the pros and cons, the upsides and downsides, and were able to see that this is adding benefit for the project.”
Simplify, standardize, industrialize
This approach to improving operations is part of a program called SSI, which means “simplification, standardization and industrialization,” Rød explained. “I think the biggest benefit so far has been in simplification— defining the right concept, defining what to build and reducing complexity.”
Another advancement, he said, was to step back and redefine what standardization means. “A lot of people believe standardization is only about hardware, about tangible things, but it’s also about how we are interacting and collaborating with suppliers,” Rød said. Inviting input from suppliers is one way to standardize requirements by capitalizing on their expertise and “making sure they are working on their home turf, so to speak.”
The end goal is to become more predictable as a company regarding project execution and project management so contractors know what to expect from Statoil.
When it comes to hardware, one of the easiest things to standardize is components, not necessarily the end product, he said, pointing as an example to the various pieces that make up a subsea production system. Making this shift requires a willingness on the part of the operator to reevaluate some of the components it used to have tailor made.
Another more straightforward instance of how Statoil is leveraging standardization is the freshwater makers it installs on offshore assets. Using the same system across the board resulted in enormous cost savings, reducing capex by nearly 90%. “This is an example of good collaboration between operator and supplier,” he said.
Automation, digitalization improve safety, reduce costs
Statoil also is realizing efficiencies through automation. According to Rød, drilling automation has delivered considerable gains. Used with great success last summer in the Barents Sea campaign, drilling automation delivered greater efficiency in performance and allowed drillers to detect issues and problems earlier. “This means less downtime and fewer sidetracks,” he said, “and that improves safety.”
Automation allowed Statoil to avoid drilling two sidetracks during the campaign when the automated system picked up an anomaly that the driller missed. The overall savings were 100 million NOK (US$12.9 million) over the course of five wells.
Statoil also is making advances in digitalization, which is enabling a move toward safer operations. “I strongly believe digitalization is impacting what we build, how we build it and how we operate,” Rød said.
Proof of the organization’s willingness to push the implementation of digital technology was the announcement in early November 2017 that Statoil had opened the Valemon control room in Bergen, where onshore staff operate the North Sea Valemon platform, the first in Statoil’s portfolio to be remotely controlled from land.
“Safety is priority No. 1 when we assess new concepts, new systems and tools,” Rød said, noting that the important thing about Statoil is, “We are never afraid to implement new technologies and new innovations to take us a step farther.”
Strategic direction at Statoil is determined by embracing new technology and driving for continuous improvement, he said. “By applying technology, innovation and creativity, we are building a big toolbox of concepts and technology that enables us to tailor make our business cases to create value and enhance recoverable reserves.”
Defining a competitive advantage
Shell has concentrated its efforts over the last three years on what Edwin Verdonk, vice president of development, deep water, called, “restoring competitiveness.”
Having operated in deep water for 40 years, Shell is proud of its performance as a leader in overcoming technology challenges.
Today, the focus is on finding “good, integrated low-cost economic solutions for our deepwater fields,” Verdonk said.
The seven-step solution
Getting to the heart of “restoring competitiveness” means recognizing areas for improvement, Verdonk said, noting that Shell has identified seven of these to help reach that goal.
The first is competitive scoping, which he explained as, “responsibly determining what the minimum technical scope is for a particular development” and recognizing that some of what the company was doing added unnecessary complexity.
Historically, Shell had constructed what Verdonk called “extremely heavy wells that had an incredible number of pieces of steel.” When company experts looked at the designs from a risk and safety perspective, they found that the wells designed this way did not materially improve safety.
Minimizing complexity took a different form on the deepwater Kaikias Field in the Gulf of Mexico (GoM). “Previously, we would have an extra flowline or umbilical,” Verdonk said, but in evaluating a range of options, Shell and its partner, MOEX NA, decided to tie Kaikias back to the nearby Ursa platform with one flowline and one umbilical.
With the scoping complete, the next focus is efficient execution. “Do it right in the first go and really look at all the waste in execution,” he said. “Be more nimble and agile.”
One of the ways Shell has improved efficiency is by looking at the way it had been drilling wells and realizing much of the work was being performed sequentially. “We found out we could do many things in parallel,” Verdonk said, and this shortened the drilling process. “We were able to achieve on average 35% reduction in drilling time over wells we drilled in 2014. Now we are drilling wells at 50% of the cost incurred in 2014.”
Efficiency does not end there though. “Once executing, we are finding much slicker and smarter ways to manage logistics and the sequence of activities to get a lot more cost out,” he said. For the Appomattox Field development program, Shell was able to take 25% of cost out after the final investment decision (FID).
Shell also transformed its supply chain, completely reevaluating pricing and cost structures.
“Most people think you just drive prices down,” Verdonk said, “but this goes a lot further.” In Shell’s case it is work that is being done in cooperation with suppliers. “Simply by sharing and making helicopters and vessels available to our total portfolio, we have been able to take $600 million out of logistics costs over a number of years on that bill alone.”
The fourth way the operator is saving money is by putting technology to work on such things as well completions. “We used to complete development wells in extremely large hole sizes and with a lot of expensive and difficult equipment to give us endless flexibility,” he said. “Then, Shell asked the question, ‘Can we not devise, from a technology point of view, a much slimmer version of this completion?’ The answer was yes.”
Verdonk continued, “We found out through testing in a technology setting that slimmer completions deliver similar results as bigger completions.”
This realization has led to a transformational change in how Shell evaluates and executes deepwater projects, he said. “These are not just ideas. This is happening now.”
According to Verdonk, Shell also is investing in digital technology. “Digitalization can be transformational for our industry,” he said, in much the same way it has changed the way individuals communicate, shop and interact. “That wave of transformation needs to be fully embraced in the hydrocarbon industry.”
In essence, Verdonk believes every element of the deepwater sector is going to be touched by digitalization in some way. “I’m extremely excited about the very positive effect this can have,” he said.
Another critical focus for Shell is cutting cycle time. “By managing cycle time, we raise the competitiveness of our deepwater projects,” Verdonk explained. “We had been looking at deepwater projects sequentially,” and that approach was slowing down execution.
The operator recognized that it could take positions earlier in the program while some phases had not been completely finished. “Parallelizing activities and compressing certain stages can take a number of years out of the very long time lines for constructing deepwater hubs,” he said.
Using multiple yards to execute components simultaneously is allowing Shell to achieve significant efficiencies. Successfully bringing the pieces together is a matter of meticulous planning and active management of every part of the project. According to Verdonk, “It requires intervention and constantly looking at all of the components, particularly those on the critical path.” That focus on progress and execution is what he classifies as “flawless integration.” It requires top-class integrated schedules, Verdonk said, “but we have not run into any issues whatsoever.”
The next item on Shell’s list is system engineering, acknowledging that the total value of a project is in the total system. That means looking at a project from the barrel price of oil all the way to the platform and the subsurface, Verdonk said. “Shell is much more able now than before to model aspects of a project to see what the total effect is on the total value of the system if we change any element of the value chain.”
On Appomattox, for example, Shell has every piece of equipment on the platform electronically stored in a 3-D format that can be used to show how components have been inspected, how they interact and how they affect the system. “This is helping us to manage the total system,” he said.
Finally, Verdonk said, the company is working through joint industry projects and joint development programs to advance safety, collaborating on technologies such as capping systems. “Together, we can come to a good technical solution for an emergency,” he said.
Shell also has been supporting high-pressure solutions for 20-ksi operations, hoping to develop a costeffective way to unlock resources that are difficult to access because of high pressures. The way the industry works together is changing, Verdonk said, and he is optimistic about the potential successes that could be achieved. There is a higher level of cooperation, he added. “It is happening, but from an efficiency point of view, we can always do better.”
Doing things better really is the ultimate goal.
The oil and gas industry must achieve greater efficiencies to make it competitive, according to Verdonk. “Deepwater will need to constantly improve itself and reinvent itself to stay on that competitive edge,” he said.
Catching the runaway dog
The need for competitiveness in an exacting low-price environment is precisely what drove BP and its partners, BHP Billiton and Chevron, to hit the reset button on the Mad Dog 2 development in 2013 when the total project cost surpassed $20 billion.
“We basically went back to the drawing board,” said Bill Steel, BP’s Mad Dog 2 project manager. “It was a bold decision for the company leadership to take with a project at that level of maturity.”
It was evident that the original plan was not going to be cost-competitive, so it was important to consider the project with the mindset that every dollar matters, he said. “We were very deliberate and thoughtful about the decisions we had to make. The team was given the time and space to get it right, and it was essential that we get it right after the recycle.”
Given where the project stands today—with development cost estimated at approximately $9 billion, a reduction of more than 50%—it is apparent the team did just that. But the journey to success was not a cakewalk.
It began with the team developing a tiered decision-making process to manage the myriad decisions.
According to Steel, the most significant Tier 1 development decision was defining the strategic theme. And the most fundamental Tier 1 decision was the one that determined the production system that would be used. The choices, he said, were grouped into three themes: “start small,” “transformer” or go “all in.”
A small facility would allow the operator to begin producing the field and use reservoir performance data to make further decisions. A unit that could be transformed would be a larger facility with a reasonable level of capacity to manage a downside reservoir outcome but with the capability for expansion in the event of a greater volume of production. The “all-in” decision would be the biggest option, with the maximum number of wells and the biggest water injection capacity to manage life-of-field development for a huge reservoir outcome.
The team evaluated these options and chose the middle road, selecting a semisubmersible as the alternative to the original spar concept.
For the spar, Steel said, “We had massive topsides, three big modules, accommodations and a fl are tower,” which would require a time-consuming and expensive offshore hookup and commissioning. “For our needs, a semi was more appropriate because it could be fully built onshore with quayside hookup, and it could be built to allow room for expansion.”
With the design basis established, BP began the process of specifying the design, which began with an assessment of its operating semisubmersibles.
“We talk about Mad Dog 2 as an Atlantis lookalike,” Steel said, explaining, “Atlantis has worked well. Why wouldn’t we base this next development on something we know has been successful?”
The proposed field layout features subsea wells tied back to a semisubmersible of the same basic size and design as Atlantis. “What we realized is that we didn’t want to constrain ourselves if there was an upside outcome,” he said. There is a lot of prospectivity in the area, and BP had appraised the field and determined that it has the potential to be a world-class reservoir. “With a small pre-investment in real estate, we get the capability for future expansion,” Steel said.
If more discoveries lead to additional tiebacks, water injection capacity can be added along with processing capacity. “Subsea architecture is very scalable,” Steel said, “and there is a lot of flexibility in the FPU [floating production unit].”
According to Steel, the downturn in the oil price allowed BP to talk more directly with suppliers to achieve better alignment. The message was one of solidarity rather than competition.
“We’re all in this together,” he said. “We told our suppliers we thought we could make Mad Dog 2 work as a deepwater project, but we needed their help. These people have great ideas, and they know their equipment. What we had to do as a company was demonstrate to them that we were serious about being open to their ideas.”
BP was challenged with finding a way to change preconceived expectations and demonstrate the company was in its intent to take suppliers’ ideas onboard. “We tried to be provocative in giving them some ideas we were up for to show we were serious. In the past, we haven’t always listened. This time, we didn’t really need bespoke specifications. We wanted industry standard equipment,” Steel said.
What BP wanted was “industry-led solutions,” which meant suppliers were being asked if any of their standard products would fit BP’s needs, meeting functional specifications rather than detailed specifications outlining materials and design conditions.
In using more standard components, BP could lower costs and at the same time improve safety, reliability and scheduling using proven equipment that suppliers could build with the basic components they had on the shelf. According to Steel, this approach paid off. As an example, he said, “We’ll take delivery of our first subsea trees this year because OneSubsea had the basic building blocks available.”
In addition to employing standard equipment, BP is building on automation—a focus of its modernization and transformation agenda—to find ways to increase efficiency and effectiveness of equipment inspections and ensure the production system’s operability and maintainability.
Some of the efficiencies BP achieved were based on using equipment identical to the kit on Atlantis. The knowledge that it had worked reliably was one of the drivers. Another was knowing exactly what that specific equipment had cost.
“We knew cost discipline was going to be important,” Steel said. “We dug out invoices and contracts from Atlantis and said, ‘We want that piece of equipment at that price.’”
Because Mad Dog 2 was sanctioned in the aftermath of the oil price drop, BP was forced to make cost discipline a priority, but according to Steel, an upward trend in oil and gas prices will not change this mindset.
“What we’re trying to instill is a culture across our global projects organization that discipline is good for all seasons,” he said. “We can’t get sloppy again. We need to avoid price inflation because of inefficiency; otherwise, deep water won’t be competitive in the long run.”
Profiting from partners
Another departure from the beaten path is the continuing collaboration among the co-owners of the Mad Dog 2 development. “We give them a lot of access to what’s going on in the project, and they give us a lot of technical input,” Steel said, and that has led to shared technical lessons.
One of these is how to improve water injection. “BHP has been operating a large-scale waterflood on the Shenzi Field in the deepwater GoM for several years,” he said. Because Mad Dog is a similar reservoir, a lot of BHP’s experience is relevant, which has given the operator a role in advising on system design and setup.
It also is capitalizing on Chevron’s project management experience with the recent construction of the Jack/St. Malo production system at the Samsung Heavy Industries yard in South Korea. “Chevron shared their experience not only on project management, but on engineering, safety, quality management and how the yard works,” Steel said.
Continuing the crusade
Going forward, modernization and transformation will guide BP’s project development. While there will be specific lessons from Mad Dog 2, Steel said, the broader objective is to transform BP’s business.
“What we’ve done on Mad Dog 2 is not unique in BP, but it’s consistent with changes we are implementing across the upstream organization and our global projects organization,” he said.
The results thus far are impressive. Although BP made a deliberate decision not to chase every barrel in Mad Dog 2, the expectation today is for production to exceed 100% of the original estimated reserves, and this will be achieved at about half the cost.
BP has rebalanced the cost and revenue equation such that its GoM business free-cash breakeven point is less than $40/bbl, roughly half of what it was in 2014, and has managed to push down production costs 35% since 2015.