What do Superman, LSD and World War II have in common with the discovery of the first offshore field in the Gulf of Mexico (GoM)? Other than the year history books give credit for discovery or start—1938—each demonstrates the success or failure of collaboration.

That first field—the Creole—was operated by Pure Oil Co. and Superior Oil Co. and was located a mere 1.9 km (1.2 miles) from the shores of Cameron Parish and 21 km (13 miles) from the nearest coastal community of Cameron, La. The platform—built on timber pilings in water depths of 3 m to 4.5 m (10 ft to 15 ft)—represents the first of what would be many steps out onto the continental shelf of the GoM.

The offshore platforms of today are made of steel, and it is not uncommon to find them operating in water depths greater than 500 m (1,640 ft) and in fields located more than 160 km (100 miles) from land.

The significant planning and development processes necessary to bring highly technical and highly challenging GoM frontier resource plays like the Paleogene online require long lead times and highly sophisticated technologies. Collaboration—the most basic of technologies—has long played a key role in the development of the GoM from a single fledgling field to a global powerhouse of many.

Tapping the Paleogene

The Paleogene, aka Lower Tertiary Trend, is the next exploration and production frontier in the GoM. It also is an important one for the U.S., according to Cindy Yeilding, vice president and director of appraisal for BP.

“Historically, the U.S. has—since the 1970s—been getting two million to three million barrels per day of production primarily from the shallower waters of the Gulf of Mexico Shelf. That number started to decline around 2000, but fortunately deepwater Miocene production started to ramp up,” she said. “The deepwater Miocene reservoirs ramp up quickly and provide excellent production for five to 10 years before starting to decline. We see production from the Paleogene reservoirs starting to fill the vacancy as the Miocene trend starts to play out and begins to decline.”

The industry has found about 6 Bboe in the Paleogene since entering the play in the early 2000s, according to Yeilding.

“We think there’s 15 billion to 25 billion barrels yet to find. We’re still in the early days of exploration in the trend,” she added.

BP’s success in the Paleogene includes discoveries at Kaskida, Tiber and Gila. The Kaskida exploration well, drilled in 2006, is located on Keathley Canyon Block 292 in about 1,786-m (5,860-ft) water depth and is about 402 km (250 miles) southwest of New Orleans. The well was drilled to a total depth of about 9,906 m (32,500 ft) and encountered 244 m (800 ft) net of hydrocarbon-bearing sands.

In 2009, BP discovered oil in the Tiber prospect in the ultradeepwater of the western GoM. It is, according to a BP-issued press release, believed to be one of the largest finds in the region. Drilled to a total depth of 10,685 m (35,055 ft) including 1,259 m (4,132 ft) of water, the Tiber exploration well is one of the deepest ever drilled.

BP announced in 2013 the discovery of its Gila prospect located about 483 km (300 miles) southwest of New Orleans in nearly 1,524 m (5,000 ft) of water. An initial discovery well was drilled to a total depth of 8,906 m (29,221 ft), but further appraisal drilling will be required to determine the size and potential commerciality of the discovery.

“Our ability to find new accumulations is pretty good. What we can’t do yet is develop some of those accumulations we have found because of higher pressures,” Yeilding said.

Different approach to developing the Paleogene

The success of the GoM offshore industry is due in large part to the collaborative efforts of many over a span of seven-plus decades. As the industry continues to march into the deeper waters of the Outer Continental Shelf in the years to come, the systems and equipment necessary to safely and efficiently develop the fields beneath the seafloor will either require redesign or creation.

In February 2012, to meet the development demands of its portfolio of ultradeepwater GoM Paleogene discoveries, BP launched Project 20K. The multiyear initiative seeks to develop the next generation of systems and tools necessary to unlock the next frontier of deepwater oil and gas resources that are beyond the reach of today’s technology.

The project will enable the company to explore, develop and produce new deepwater resources that are at pressures up to 20,000 psi and temperatures up to 177 C (350 F). The company estimates it could potentially access an additional 10 Bboe to 20 Bboe across its global portfolio during the next two decades with the application of Project 20K technology.

The project’s four focus areas—well design and completion; rigs, risers and BOPs; subsea production systems; and well intervention and containment—guide the research and development efforts of BP and its partners from industry and academia.

For Stuart Rettie and Mick Leary, Project 20K team leads for the company’s Global Projects and Global Wells groups, respectively, the project is a departure from the norm in many ways.

“It is a technology development project and not a specific asset development project,” said Rettie, projects director. “Our role is to develop the entire holistic capability for [operating at] 20,000 psi; that’s being able to drill, complete, produce and intervene on these wells. About 70% of the project is wells-related, so we are approaching this project a little bit differently.”

Leary, wells director, added that the project is figuratively “starting on a cleaner sheet of paper than we’ve ever done in the past and really looking at what it takes to safely, reliably and efficiently drill, complete and intervene on these wells.”

“The hardware and designs we develop will be implemented by future projects, whether they are in the Gulf of Mexico, the Caspian Sea or Nile Delta,” Rettie said. “Those are the three areas we have in mind for initially deploying the technology. We are playing to one of our strengths, which is the deepwater.”

‘More hands, lighter load’

It has been a very busy two years for Rettie and Leary. The internal collaborative efforts between their two groups build upon the expertise of each to advance the project closer to its ultimate goal of first oil within the next decade.

“We’re using our major project delivery processes and systems to have oversight of the project,” Rettie said. “But we’ve got deep expertise from the wells community that’s helping us develop the technologies. The role that the Projects Group is playing is delivering the capital discipline, executing the project at a given cost within a given time and integrating the technical expertise.”

That capital discipline is critical to the project and to meet the goal of keeping the project economics in check. Rettie noted the project’s practice of a concept called “value engineering.”

“Value engineering is making smart decisions about the systems we’re going to deploy and the redundancy we may or may not need. We have an interesting model that we’ve created with Maersk Drilling [a Project 20K partner] around how we will evaluate the different systems that go onto the drilling rig,” Rettie said. “The other different thing that we are doing in this project is taking a holistic mindset. This isn’t just an upgrade to a 20,000-psi capable rig. This is about everything that it takes to deliver the entire capability at one time.”

To that, Leary added that the internal collaboration extends beyond the doors of the Houston office. “If we look at the regions around the world where this could be applied, there’s integration between various different regions and Project 20K.

“We make sure that as we develop these designs and equipment there’s been a working relationship that provides input to those designs from the various regions so we don’t get to a point where we’ve developed all of this and they say, ‘We don’t like this or that about it.’ All of that integrated input is being put in up front as opposed to doing our own work and sending it out to the regions in a vacuum.”

The internal team has grown during the last two years with the addition of several new external partners. Nine months after announcing the initial project launch—in November 2012—BP awarded the first contracts to FMC Technologies and KBR. The FMC Technologies contract is collaborative but places them as the leading partner to design, develop and manufacture the subsea production equipment for the project—including the 20,000-psi subsea tree and high-integrity pressure protection system (HIPPS).

Project execution and management plans, risk assessments, cost and scheduling estimates, and the systems engineering management fall under KBR’s umbrella of project responsibilities.

“KBR’s role is to act almost like a central clearinghouse. We have a couple of hundred new technologies to develop, and the way we monitor development is through ‘technology readiness levels,’” Rettie said. “As an idea moves from napkin to prototyping, we have a process to test the readiness. With all the complex interactions that have many interfaces in this project, we need everything coming back from the various entities so we can monitor and understand where we are on the maturation of the various technology readiness levels. That way we can ensure that everything moves in the right sequences with the right timing.”

Leary added that it is “important to note that as we look at all of the interfaces, we’re all dependent on one another. From a well design and completions standpoint, we need a rig to construct that well. From a subsea production system point of view, there are many interfaces between the well that was constructed and the subsea systems, and from a capping and containment standpoint, we have to be able to go back and interface with all of that previously installed equipment.”

Maersk Drilling was selected in 2013 as BP’s partner to execute the development of the rig, riser and BOP designs. In the same year, BP launched a strategic partnership with the University of Texas at Austin (UT) to support several leading-edge oil and gas industry research projects. The work conducted for Project 20K will study the impact of “human factors” on the drilling process and develop new systems that can enhance safety and efficiency. UT’s efforts will join with the long-established and BP-supported materials and corrosion research efforts underway at the University of Manchester and “complex systems integration” analysis at the Massachusetts Institute of Technology.

“This project has provided a catalyst or foundation in the industry for further collaboration,” Leary said. “This technology development has kicked off API activity around the standards that various pieces of equipment are designed to, and we’ve seen BSEE [Bureau of Safety and Environmental Enforcement] also take a very engaged interest in development of this technology.”

He noted that BSEE has been involved in the API standards activity and is very keen from a regulatory view to see an aligned set of standards that industry will work from as opposed to “each and every company creating their own design standards.”

Collaborative integration

The integration of both internal and external collaborative groups is a key Project 20K theme. Rettie noted that the integration of the Projects and Wells groups and, in turn, the project’s integration with the Exploration Group and the very early involvement in the project by suppliers is also an approach different from projects of the past.

“I don’t think we’ve ever before brought the drilling contractor in as early as we’ve done with this project,” he said. “Together, we can jointly look at the processes for what it takes to drill a well and can effectively optimize the drilling rig for that purpose.”

But why advance the technology in increments of 5,000 psi? For Rettie, the answer is simple.

“Historically, industry has moved from onshore with pressures increasing to offshore and in the deepwater,” he said. “We’ve gone from 5,000 psi to 10,000 psi to 15,000 psi, and the natural step is to now go to 20,000 psi.

“Some may ask about an intermediate step, but I think the industry has wisely chosen to do it in 5,000-psi increments. Part of that fits the aspect of standardization,” he said. “One of the key levers we have to control costs in our industry is to develop standard systems. If we all work on a standard, it improves safety and reliability of these systems, and the next band for deepwater is 20,000 psi.”

Collaborative integration begins with the first focus area for Project 20K—well design and construction. This focus requires the second focus area—rig, riser and BOP design—tasks well suited for Maersk Drilling. The first also impacts the third focus area—subsea production systems—that FMC Technologies is tasked with developing.

Well design and completion

Due to the early involvement in Project 20K by the Exploration Group, the Wells Group has an enhanced understanding of Paleogene reservoir conditions. This understanding, when combined with an extensive knowledge and resource base to draw from, gives the Wells Group an edge in designing wells for these challenging reservoirs.

“These wells will need to hold up for a long life cycle of production, but intervention capability is also needed,” Leary said. “These wells will require stimulation to produce, so the design needs to enable that. These wells are a little deeper, a little hotter and at a higher pressure than other wells that have been done in the industry; thus, the components have to be able to handle these higher design loads.”

For example, many of the planned casing strings will have a heavier wall thickness and be stronger than the ones in use today.

“To effectively stimulate the well, we also will need to attain good zonal isolation across the production intervals to isolate any water sands,” Leary said. “We’re working on all of the various components in the design of a producing well, and that’s offering up a number of challenges.”

Much of the design work includes the development of components that do not exist in the market today.

“The fluids, techniques, materials and equipment—like packers and safety valves—will all have to be developed because they don’t really exist for this application,” Leary said. “There is considerable effort going into that. We’re relying on a small team but calling on specific expertise across BP to contribute in their areas of expertise. We can pull resources out of other parts of the company to help in a particular area, whether that be tubular design, cementing or fracture stimulation.”
The best well construction and completion design is still just a plan without the equipment necessary to make it possible.

The decision, Leary said, was made early in the process to take a different route to rig design.

“We picked Maersk Drilling—and Maersk Drilling picked us—to collaborate on what a 20,000-psi rig should really look like, and this has been a great relationship. It has worked very well for us, and I think Maersk Drilling would say the same thing. We bounce ideas off each other; we challenge each other—us to our requirements and them to their capabilities—to construct these wells.”

Rig, riser and BOP design

The step-change from 15,000 psi to 20,000 psi is significant, requiring equipment that will be larger, heavier and stronger than what has been used to date at 15,000 psi and below.

“For example, the 20,000-psi BOP stack will weigh about 50% more than a 15,000-psi BOP” Leary said. “Due to the weight of the BOP and the longer, heavier casing strings, the hoisting system on the rig will have to be capable of handling heavier loads than the 15,000-psi rigs of today.

“However, we also want to incorporate inherently safer design concepts into the layout of the rig. We are thinking about the workflow of the well construction process and how the rig should be set up to safely and effectively do the activities.”

The philosophy and approach is different than most have taken in the design and building of a typical rig, Leary noted.

“Oftentimes we’ll contract for a rig when construction has already started or may be complete; then we try to make adjustments for our particular well program. Thus we end up retrofitting where practical as opposed to designing in the requirements from the start.”

Rettie added that the approach goes back to capital discipline on the part of the project.

“We’re not going to start with a clean piece of paper on everything because if you start out with an unlimited checkbook, you could end up with a design that could do absolutely everything you imagined needing it to do, but would it be a cost-effective tool?” he said. “It would not be economical. Some of the things we’re doing are based on the standards we want to adhere to. Today’s standard wellhead connector—the 18 ¾ in.—we’ve said, ‘OK, that’s a fixed point, and we’re going to stay with that because it is out there and can satisfy our needs.’ We’re not going to go far beyond that because it starts to become uneconomic.”

In examining the design and functions of today’s rigs, the team is looking for the features that add value to the design and the work scope contemplated, noted Leary.
“We’re asking questions like, ‘How many pumps do we need to have?’ and ‘How much deck space do we need?’ We’re focused on delivering a product that is competitive and that can deliver a cost-effective, reliable well in a safe and efficient way,” he said.

In selecting a design, the Project 20K team selected a drillship as its first rig design.

“When we looked at the requirement in the GoM, primarily with the depth of water and the depth of these wells combined with the casing loads, you can get more payload onto a drillship than a semisubmersible for an equivalent cost,” Leary said. “When you look at our GoM portfolio, the drillship is going to be more cost-effective and efficient in delivering results.”

Maersk Drilling has considerable range of experience and resource base to draw from in the design of the necessary equipment for Project 20K. For Frederik Smidth, chief technology officer for Maersk Drilling, working with BP presented a real opportunity to work on a project that is, “from an engineering perspective extremely interesting and challenging.”

The project, he believes, aligns nicely with Maersk Drilling’s strategy to grow in the deepwater and ultraharsh environment segments.

“We want to grow in what we call the ‘post-technology and operationally challenging areas.’ That is where we believe we can justify being and where we traditionally have been more successful,” Smidth said. “Project 20K is actually spot-on. It is in our main strategy to go for the 20,000-psi area. We want to be in deepwater. We want to be in the challenging part.”

Getting to start with a “cleaner sheet of paper” is a unique opportunity for Maersk Drilling, Smidth said. A project’s time or financial limits often determine what can be done on the design side.

“We’ve done it once or twice before, mainly on the jackup side of the business. We were able to improve the efficiency of the jackup significantly. Our goal with Project 20K is to do the same on the deepwater side,” he said.

Another unique aspect to this project was that the company had a client in BP that was willing to share and listen to the design visions of Maersk Drilling.

“We have a client telling us what its pain points are and where it sees the pain points being and so on,” he said. Another huge advantage in working with BP is that Maersk Drilling gets access to data.

“We get access to their operational and technical knowledge, especially when we’re talking new development like this,” he said. “They have experts we can draw on and can access their knowledge.

“If we get the right people from the operator to open up and tell us what they like and what they don’t like, we can understand their problems and try to understand their cost structure where they spend the money and where they don’t spend effectively. If we can help them improve spending efficiency, I think that’s a gain for all of us.”

Smidth finds that in balancing the needs vs. the wants in the new rig design, being very disciplined in addressing and justifying each is critical.

“That’s how we build. We have to justify things either from a safety point of view or operational efficiency point of view. Saying you want a dual-drill rig or two BOPs, you’ve got to be able to justify it.”

There are a number of challenges in designing a rig, riser and BOP system for 20,000 psi, challenges like the higher pressures and higher temperatures.

“But as long as you know beforehand, we can design the ship for handling a bigger BOP and heavier riser,” he said. “The challenge is determining what standards we design against and how we design the internal components of the BOP as it has to be able to handle not only high pressure but also high temperatures.”

The larger sizes and heavier weights of the equipment like the BOPs, casing strings and drillpipe will have an impact not only on the design of the rig but also the handling systems.

“The handling systems we’ll see will be similar in types to what we see today but stronger, I would say,” Smidth said. “Obviously the ship cranes and the mobile cranes and support systems and so on will have to be designed to handle the weights and size.

“We have not completed the design yet, so I’m a little bit hesitant to make conclusions. But the way we handle drillpipe and casing and so on today—I think that in principle is going to be the same, but the equipment has got to be stronger to handle the higher weight and bigger dimensions.”

Smidth would not comment on details about the size of the drillship other than to say it “will be bigger than what we see today” and that it “will have higher load-carrying capacities.”

Subsea production systems

The decision was made early on in Project 20K that the 20,000-psi hydrocarbons would not be taken to the surface, according to Rettie. To accomplish this, BP partnered with FMC Technologies to develop the suitable subsea production systems with a HIPPS necessary to safely produce from the Paleogene reservoirs.

For Brad Beitler, VP of technology for FMC Technologies, working with BP on Project 20K was a natural extension of work the company had already begun a few years ago.

“We had actually started an internal program funded by ourselves to develop high-pressure, high-temperature equipment,” Beitler said. “We had a road map that took us over a period of five to seven years that would take us from where we were at the time.”

The company was developing at that time its 15,000-psi systems for temperatures in the 120 C to 150 C (250 F to 300 F) range, according to Beitler.

“Our road map took us all the way out to 30,000 psi at 500 F [260 C] over a long period of time, with some various intermediate waypoints. One of them was 20,000 psi at [177 C].”

FMC Technologies met with several of its customers at the time, including BP, to get feedback. Those early discussions, in Beitler’s view, are what led to the eventual partnership for Project 20K.

“When it came down to BP actually looking at some of these leases they have in the Gulf that are going to require this kind of equipment, I think they had it in their minds there was a couple of us that could do the work,” he said. “At the end of the day, they probably looked to see who was the farthest along, who could quickly move the direction that would favor them. We’d been doing some work with Shell on some of their fields and with others. I think BP felt like, at the end of the day, when they made the decision, we would probably be quicker out of the chute and provide them with the kind of integrity they needed for this kind of venture.”

One of the key components in subsea production is HIPPS. HIPPS is not a new technology, but it is a significant one for ensuring the safety of production from HP/HT reservoirs.

“HIPPS allows the well’s flow to be shut off right near the tree if it detects any kind of buildup in pressure in the flowline,” Beitler said. “It allows the operator to create a specification break on the seabed and use a thinner wall flowline and production riser that’s more rated toward the flowing pressure of the well as opposed to the shut-in pressure of the well. The HIPPS is a triple-redundant valve that quickly shuts off flow if it detects any kind of high-pressure transient moving through the flowline. The HIPPS lets us use existing technology for the flowline and production riser and eliminates 20,000-psi hydrocarbons to the production facility. There’s a lot of technology in a subsea HIPPS, and it’s a unique piece of technology that’s really geared up for high-pressure circumstances like this.”

While HIPPS addresses one safety angle, another looks at the finer elements in the design. Like the rig design, many of the components will be larger in size and heavier in weight. However, a majority of the design and safety enhancements for Project 20K subsea equipment focus on smaller components like materials used in seals.

“The base materials themselves probably aren’t going to have a lot of enhancements,” Beitler said. “We’re looking at everything, ensuring they’re all adequate and that we don’t go through any phase changes. But at [177 C], you don’t get a whole lot of changes in materials.

“As we look at the long-term effects of temperature on materials, there is a possibility that we may want to increase our safety factors a bit to make sure that the long-term effect of temperature doesn’t reduce the mechanical strength. So far, we haven’t seen anything like that. It’s a possibility out there as we go through the testing.

“With regard to things like the seals, that’s why we’re doing so much temperature testing. It’s to ensure that we understand the long-term effects of temperature and pressure on the materials we use for seals to ensure that the seals don’t flow or do strange things under those kinds of conditions. We test the seals to 20,000-plus psi, some to 25,000 psi, and to temperatures much higher than [177 C], more like 400 F to 450 F [204 C to 232 C], just to find out what the operating envelopes are.”

Of all the types of materials available for seals, elastomers are probably the most difficult, according to Beitler.

“There are a lot of different elastomers for seals out there that are good at really high temperatures like this. But in this case they also have to perform over a range of temperatures. The seabed is close to freezing, and the flowing temperature is close to [177 C], but they have to seal under both of those conditions. The temperature range then becomes the issue.

“There are a few elastomers that will do that, and we have to ensure that the ones we select are going to be the ones that can a last a lifetime and have the integrity that we need. It presents a lot of issues and a lot of opportunities for basic research in these materials and how we assure their longevity and integrity.”

Beitler believes this project will have a widespread impact on the rest of the Paleogene (Lower Tertiary) in the GoM and around the world.

“The work we’re doing here is groundbreaking, and the things that we’re doing will not only set the pace but also the basic design guidelines for everything else done in this kind of environment and these formations,” he said. “I believe API will then take what has been developed and put it into their regulations and specifications. I think other oil companies will look very closely at this and ask the question of ‘Why design something different? Why not just use what’s been proven?’

“First of all, the regulators are going to be scrutinizing this very carefully, and if this is something already passed by the regulators, then that becomes a lot easier for the oil companies to use for their development. I think this is going to have a huge impact on the future of this whole Lower Tertiary area. We don’t take it lightly. This is a big responsibility that we all have—BP, FMC Technologies and Maersk Drilling—to get this project right.”

Bright future

The size and scope of BP’s Project 20K doesn’t end with BP, FMC Technologies and Maersk Drilling. There are future partnerships planned that will address the hundreds of new pieces of kit necessary to develop and produce the Paleogene. From umbilicals to valves, casing strings to production tubing, personnel training and more, enhancements to all will be needed. The capital investments necessary to support R&D efforts, testing facilities, manufacturing facilities and more will keep the industry very busy in the coming years. A decade or more of technology development for Project 20K will further foster the collaborative spirit that has revolutionized the GoM offshore industry since its start at Creole so many years ago.

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