As the industry looks at the challenges presented by deepwater operations, it is apparent that in many cases today’s challenges are very much like those of the past few decades.

Taken at face value, such a statement might imply that the industry has not made significant progress, but nothing could be further from the truth. Technology advances have extended the reach of E&P operations into deeper and more inhospitable operating environments. And as the industry continues to push the limits of current capabilities, there will continue to be innovations that provide improvements in safety, efficiency, and productivity.

Macondo

The Macondo blowout in the Gulf of Mexico (GoM) on April 20, 2010, was a defining incident for the industry. Post-Macondo operations will reflect more stringent regulatory and safety requirements. Though the mainstream press would have people believe otherwise, these are changes the industry is embracing.

Robert Patterson, vice president of upstream major projects, Americas, at Shell, lists the loss of faith in the industry’s ability to work safely as one of the biggest deepwater challenges. “We know how to safely and responsibly find, drill, develop, and operate fields in deep water. But we have lost some confidence with the public. I think that is one of our big challenges in deep water. We need to earn back the trust that we can develop this frontier area and other frontier areas as well.”

Shell has the distinction of bringing onstream the deepest drilling and production platform in the world with the Perdido spar in the GoM. That project was executed with 10.5 million man hours with no lost time incidents recorded. Impressive as this achievement is, the safety record is not enough.

“Safety is a matter of ensuring standards and procedures are complied with and showing consistent competence. It is about investing in a culture that supports safe and responsible delivery,” Patterson said. “Advertising won’t be sufficient to win back public confidence. We have to demonstrably do our work well every day.” Oivind Reinertsen, head of US offshore for Statoil, agrees. “It is important for the industry to come back into deep water and start the business again,” he said. “We have been working diligently with the regulators for the past year since Macondo to determine what it takes to go back to work in deep water, and I think together we have been able to identify what it takes.”

The first priority, of course, is to be able to prevent such an accident. “We have been able to get the necessary equipment in place to handle a blowout like we saw with Macondo,” Reinertsen said. Over the past year, Statoil has worked to verify all of its equipment and can document it according to the new rules and regulations that apply to these drilling units.

GE Oil & Gas is investing in technology for improving safety as well. Manuel Terranova, senior vice president, regional operations and global sales, said his company is trying to bring the aviation mindset to oil and gas. “It operates under a tighter regulatory regime than what we’ve been used to,” he said. “We’re trying to leverage from that experience. Specifically, we are looking at the shearing capacity of our rams on the blowout preventer. We have upgraded our shearing capacity to 5,000 psi as a first step. We are also rolling out a hydrostatically augmented shearing capacity. This is going to use the hyperbaric, or hydrostatic, pressure at depth to close the ram.”

Another improvement GE has made is to place more position indication sensors on the equipment itself. “We’re also putting sensors in the BOP core that will relay its position to topsides, so there will be a visual inspection point if the ROV has to get sent down.”

The other GE product in development is called the Drilling I-Box, a data logger that captures housekeeping events on the BOP. “Every time a valve or solenoid or some kind of element on the BOP moves, this unit will capture that event, much like a black box would capture the event on an airplane.” The data are logged, making them available for analytics at a later time. The hope is that this housekeeping data will be useful for predicting and preventing failures.

“This whole notion of capturing the data and then utilizing it to make predictive suggestions to the operator to avoid nonproductive time (NPT) on the rig is something that we’re leveraging from GE businesses,” Terranova said. “We know it works in those verticals, and we’re very confident it’s going to work here.”

Drilling technology

Jeremy Lofts, senior director of strategic business development at Baker Hughes, identified drilling challenges as one of the major hurdles for deepwater operations. Lofts, based in Brazil, said Baker Hughes is performing more than 50% of the drilling for Petrobras, mostly in deep water. “We have to have very sophisticated drilling and evaluation systems here. The research and design that is in our technology is huge,” he said. “In deep water we are measuring a whole host of things, and each sensor includes complex electronics and mechanics – arguably more complex than getting us to the moon! Reliability therefore is critical. If one part fails, it often means a bit trip that not only causes 12 hours lost time but more importantly may mean losing data and information over that interval.” A hole in geological data reduces understanding of the reservoir, he said. “When wells are being drilled 20 km (13 miles) apart, the operator needs all those data.”

One way Baker Hughes is improving reliability, Lofts said, is by taking a fresh look at what reliability means. “Statistical analysis of each component life is helping to identify and reduce this risk,” he said, explaining, “retiring equipment before it fails is a bit like taking your car for a service at a pre-set interval. We’ve got to work out if it is 6,000 or 5,000 or 4,000 miles and then make sure we schedule the service appropriately before equipment problems occur. We took the best reliability experts from the aerospace industry to change the game because the first thing you want to do on an airplane is arrive and get off! Reliability is the same for us here.”

A second challenge is delivering real-time data to help drillers monitor equipment status and allow geologists steer to, and in, the reservoir. Real-time data improve drilling operations by presenting decision-makers with critical information while drilling is actually happening.

A third drilling challenge is to achieve greater operator cost efficiency through improved ROP. “We’re finding in Brazil that active monitoring of the drillstring and the bit are allowing us to fine-tune and improve ROP significantly,” Lofts said. “There has already been a big breakthrough, and as we go forward, further gains in active real-time drillstring monitoring and technology, along with the right expertise, will further speed up the ROP and bit life, delivering a magnitude of change.

Skip Mick, project manager, GoM deep water, Noble Energy, believes the complexity of drilling operations often is misunderstood. “There is a lot more science and technology involved in drilling than most people understand, and the process brings with it a lot of technical complexity, which can translate to risk if not handled correctly.” Well design is critical, Mick said. “A ‘first principle’ in drilling is not to let the well to get into a situation where it can blow out.”

Deepwater wells cost a couple of hundred million dollars to drill, and a uncontrolled blowout could cost many billions of dollars in damage, not to mention the intangible cost to the company’s reputation.

Before a drilling program can begin, it is important to understand the reservoir. This is particularly important in deep water because of the inherently high drilling costs. Mick identified reservoir definition as one of the primary deepwater challenges. “Reservoir analysis clearly dominates the risk in developing deepwater fields,” he said.

More wells can cost several hundred million dollars, Mick explained, pointing out that this impacts not only the economics of the drilling program but other decisions such as development timing (project cycle time), reservoir size and production rate, and whether to use wet or dry trees. Each of these has an effect on overall project net present value. Technology, efficiency.

One way to extend the limits of regional capabilities is technology transfer. Statoil, for example, is taking a look at some of the technology developed for the North Sea that can be re-qualified for the GoM.

FMC Technologies’ smart subsea controls and data management technology accumulates and performs real-time analysis on vast amounts of data. (Image courtesy of FMC Technologies)

Reinertsen pointed to water injection for pressure maintenance, common in the North Sea and now beginning to be applied in the deepwater GoM, as one example. Another is subsea processing and boosting equipment used in the North Sea and offshore West Africa that has potential in the GoM.

While technology transfer will help, Reinertsen said, new technology needs to be developed to improve production efficiency. “We need to develop technology to access more of the reservoir for fewer dollars spent,” he said. “Today there have been billions of barrels discovered in the deepwater GoM, but the recovery factor is 10% to 15% in some of these fields. When we have billions of barrels, we cannot leave 85% in the ground.”

Mike Robinson, FMC Technologies sales and marketing manager for Australia and New Zealand, identifies maximizing recovery from both greenfield and brownfield deepwater assets as one of his company’s primary technology goals.

Part of the solution, Robinson said, is to get more knowledge and intelligence from production. This is especially important in terms of flow assurance. “As we get into deeper water, we get a lot more hydrostatic head,” he said. “We have a lot more concerns over what happens with friction. The challenges multiply. We need to understand an awful lot more of what’s going on.”

Intelligence comes from physical meters and sensors as well as virtual meters that use algorithms linked to existing sensors, networking them together and linking them to higher accuracy meters such as FMC’s MPM multiphase meter. “These meters are clever because they can self-calibrate and become more accurate,” Robinson said.

Another way FMC is working toward improving production is through subsea separation. R&D efforts are directed at moving from primary to secondary separation. “We can get more hydrocarbons from the reservoir by placing the ‘factory’ on the seabed; imagine where we can place a floating production system, or a lot of that technology, on the seabed. By doing that, we make the whole system more efficient. Therefore, we can get more hydrocarbons out of the ground,” Robinson said.

An associated technology challenge for subsea single-phase and multiphase pumps is high power distribution to individually control the many pumps and compressors needed for a larger subsea operation. “A big technology gap is subsea variable speed drives to remotely control each unique pump without having it directly connected to a power supply with big cables,” he said.

Another technology challenge Robinson identified is HP/HT operating conditions, especially in the GoM. “We’re looking at demands at perhaps 20,000 psi and more than 400?F (204?C). That’s pushing the limits of known material science and classic mechanical engineering calculations.”

HP/HT also is one of the primary deepwater challenges identified by Halliburton. According to Jonathan Lewis, senior vice president of drilling and evaluation, the number of HP/HT wells is increasing dramatically, having grown 20% this year over last.

“Significant volumes of hydrocarbon exist in HP/HT formations” Lewis said, “which is driving the development of cost-effective, safe, and reliable technologies and processes to access potential reserves, many of which exist in deep water. Safely producing from reservoirs at 446?F (230?C) and about 30,000 psi is driving the development of a completely new family of technologies, from drilling fluids to tools for directional drilling, formation evaluation, and completions.” A well currently being drilled offshore Malaysia, “at the bleeding edge of the current HP/HT envelope,” is leveraging these technologies to explore previously inaccessible prospects, he said.

Cost savings and efficiency represent another set of challenges, Lewis said, explaining that given deep water rig spread rates, it is in both the operator and the service company’s interest to improve overall drilling efficiency and reduce NPT. Halliburton has invested significantly in recent years in what it calls an “optimized drilling performance strategy,” part of its broader Digital Asset initiative. “Optimizing drilling performance is about improving the efficiency by which we design, plan, drill, and position a well within a reservoir,” Lewis said. “It’s about optimizing, automating, and integrating in real time.” This requires different ways of working.

“Many of these new ways of working are being catalyzed in a completely different asset type – shale plays,” he said. “Shale plays have become a crucible for process innovation and operational change in our industry because the economics of these assets are forcing that upon the operators and the service companies. It’s inevitable that some of these process innovations will migrate to other asset types, particularly those where the costs are very high.” One of these is deep water.

Dean Watson, vice president for deep water at Schlumberger, said while best-in-class technology is critical to deepwater developments, excellence in execution on a global scale is equally important. “Schlumberger sees this as a potential differentiator in the business,” he said, explaining that a service company needs to be able to ensure that it can deliver the same quality of products and services anywhere in the world.

The “Excellence and Execution” program launched by Schlumberger in 2007 focuses on delivering service quality and consistency globally through the application of deepwater processes and initiatives.

“When getting ready for a deepwater job, it’s all about planning,” Watson said, explaining that tools developed and applied at Schlumberger allow improved planning at every level of the project. “We wanted to focus on ensuring flawless startups and flawless execution.”

Typically, operators are not just looking for one discrete service or one discrete product line. “Clients are asking for much more of an integrated approach,” Watson explained. To execute this effectively, Schlumberger assigns a specially trained integrated service project manager who manages the interfaces and ensures a seamless approach that encompasses logistics as well as general coordination management of the interfaces. The company also offers a unique deepwater certification program for anyone working on deepwater projects.

Technology qualification, integrity management

It is critical to ensure technology going into the field is qualified. Kieran Kavanagh, group technology director at Wood Group Kenny, believes reliable technology qualification is key to getting it right the first time, particularly for new technology solutions in deep water.

“We need an understanding of the technology challenges, limits, and enablers associated with potential riser and subsea solutions and how they impact facility selection,” he said. The more these are understood and thoroughly qualified prior to the execution phase of a project, the more likely they are to add value and the less likely any one of them is to negatively impact a project later through failure or under-performance. “A key challenge for us as engineering companies is the reliable evaluation and qualification of technology solutions at the front end and the systematic attention to managing integrity later so that we do all that is possible to minimize the likelihood of unplanned events or behavior during operation that stem from design uncertainties, especially the unknown unknowns, those failure modes that we were not aware we didn’t know.”

One of Wood Group Kenny’s technology goals, facilitated through joint industry projects (JIPs), is to develop industry best practice for deepwater design and integrity management. A current JIP focuses on doing just that for maintaining subsea integrity. “The goal of an initiative like this is to establish consensus across multiple operators, often supported by regulators, for what constitutes best practice,” Kavanagh said. “It has to take into account the experience we have with failure and what processes should be put in place to prevent it. We also have to ensure that we are aware of all of the technologies out there to help us maintain integrity.” This requires constantly surveying technology. “You’ve got to be aware of what different technology companies are doing and see what gaps there are between what they’re bringing to market and what is really needed. Integrity maintenance and successful qualification are tools that help avoid the cost of getting it wrong,” he said.

In addition to these indirect challenges, Kavanagh said there are considerable direct technology challenges associated with deepwater and ultra-deepwater risers. These include HP/HT environments requiring thick-walled risers or higher-strength materials, challenging or sour fluids that impact the selection of materials and fatigue performance of welded steels, higher loads that complicate installation, and high hangoff loads that affect facility costs.

“Getting it right is of very high value when the cost of getting it wrong can be an order of magnitude higher. The increasing inventory of subsea equipment deployed in deep water and the challenging environments requires us to focus all the more on qualification, design assurance, and the maintenance of integrity through life.”

Mick listed riser fatigue as one of the technology segments that requires further research. “Riser fatigue is not an exact science,” he said. “It is not easy to determine how much fatigue has occurred, so designs have to incorporate factors of safety that take that into account.”

Riser challenges go hand in hand with floater selection, a segment of the industry with its own unique challenges.

Brian McShane, vice president of marine pipeline systems and subsea systems at INTECSEA, identified harsh environments as one of the biggest challenges for floating systems, citing the Arctic as one of the most significant.

“Floating systems are facing harsh environments in Eastern Canada, Greenland, Western Australia, West of Shetlands off the coast of the UK, and also offshore Russia,” he said, explaining that there are considerable challenges in getting floating systems to work in these areas.

Reservoir depth and water depth combine to present significant completions challenges. (Image courtesy of Horton Wison Deepwater)

Another challenge is the growth in size in terms of the capacity of these systems. “They are moving toward mega-scales,” he said. “We also need companies to be able to build them and deliver them.” There is a resource constraint that will affect the time required for construction and commissioning.

There also are design challenges as floaters become larger and more rugged to contend with more demanding operating environments.

Jim Maher, vice president of Horton Wison Deepwater, identified floater integrity as one of the industry’s biggest challenges, citing design safety as a primary goal when introducing new floating concepts.

“It is important to emphasize the integrity management side of development,” he said. “We’ve been interested in learning from what we see, looking at the actual data, and using those learnings in the design process.” This is critical to improving floater designs. “The key to design is simplicity,” Maher said. “Simplicity of design leads to fewer places for failure. The goal of any design is to make the worst-case scenario as unlikely as possible.”

Human resources

There is consensus that the industry continues to face both geographic and demographic challenges. According to Patterson, stepping up to those challenges over the course of this decade will be vital for moving forward on the industry’s key challenges.

Shell is working to tap into talent on a global basis. “We have a strong deepwater capability here in the United States, in Houston and New Orleans,” Patterson said, noting that efforts to extend that capability have led to establishing offices in Lagos, Nigeria; Kuala Lumpur, Malaysia; and Stavanger, Norway; not only to expand opportunities in different parts of the world but also to expand the talent base around the globe. “Like most companies,” he said, “we are improving our development programs for people that come in and join our companies to make sure that we’re building the competence that we need and that individuals are able to grow the careers that they aspire to.”

Simply put, “The IQ per barrel is going up,” he said, explaining that the amount of technology, innovation, and human capital is going up for each barrel produced. “This is why the role of people is so critical.”

Terranova is sensitive to the demographics issue, referring to himself as “the guy in the gap,” where at just north of 40, he finds that most of his colleagues are 10 to 15 years older or younger than he is. “The generational gap in domain expertise really is an issue,” he said. “We’ve got a pretty daunting task ahead of us as an industry.”

Shell is investing in Mars B in the GoM where the company says new on-bottom seismic has unlocked opportunity by delivering improving imaging. (Image courtesy of Shell)