When it comes to the offshore industry, people need to hear a good story once in a while. The segment has been hammered in recent years, particularly since the 2014 downturn. But there are still positives coming out of this difficult sector.
One such case is Shell’s Stones Field, the deepest production facility in the world. “I’m on a number of industry committees, and one of the things that people keep saying is, ‘We really need to hear the Stones story because it’s such a positive story,’” said Curtis Lohr, project manager for Stones. “The industry needs to hear that story and wants to hear that story.”
Lohr added that the Paleogene play in the Gulf of Mexico (GoM) got a lot of people excited when oil was at $100/bbl. With oil prices more depressed, these ultradeepwater plays are riskier.
But Stones has stood out as an economically resilient project despite low prices and a challenging operating environment.
It was the Auger Field in the GoM that really kicked off the industry’s drive into deep water. Auger, located in 830 m (2,720 ft) of water, introduced the deepwater industry to tension- leg platforms (TLPs) back in 1994.
“Stones did not come out of the blue,” Lohr said. “If my team hadn’t had the experience that we had on Auger, Bonga, Perdido and BC-10—we really stood on the shoulders of those other projects, and I would like to think that Stones moves the deepwater industry forward another step.”
Since Auger the company has forged a name for itself as a deepwater pioneer. But again Stones presents a slightly different profile.
Unlike its other deepwater projects in the GoM, Shell did not approach Stones with the intention of constructing a multimillion-dollar immobile production facility using a TLP or similar design.
This is because Lohr defined it as more of a “grow as you know” mentality.
“There’s the potential for a lot of oil there,” he said. “But we don’t know whether it’s there, and we don’t know if we can produce it. We wanted to minimize our financial risk at the beginning until we learned more about the reservoir and the overall field development.”
Hence the Turritella FPSO unit. While FPSO units are still a new concept in the GoM, Lohr said it made sense up front. “An FPSO [unit] is leased, so you don’t pay all of that capex at the beginning,” he said.
“As you learn more about the reservoir, you can pay on that lease over time. Let’s say that the reservoir turns out not to be as good as expected. You can cancel the lease and off the FPSO [unit] goes to another location. Let’s say the reservoir turns out to be gangbusters (exceeding expectations). Then you can extend the lease or cancel it and bring in a larger host.” It also eliminates the capital cost of an oil pipeline, he said.
Getting to know Stones
The field has thrown some other complexities at Shell as well. In addition to the extreme water depth, the wells themselves are quite deep, exceeding 5,181 m (17,000 ft) below the mud line. And the seafloor is anything but benign.
Lohr mentioned that the 2,896-m (9,500-ft) water depth is where the drill center is located. But there’s an escarpment to the north that’s in 2,286 m (7,500 ft) of water. “You basically have this plateau, and you’ve got this drop,” he said. “Guess where the reservoir is. It’s right in the slope of that escarpment.”
Joe Hoffman, SURF lead for the Stones project, said the company did quantitative analysis studies with a number of companies to ascertain whether or not mass gravity flows from the escarpment would cause problems for the subsea kit. It eventually determined the probability of any significant event was very low.
Because of the distance from the subsea facilities to the actual reservoir location, drilling was also a challenge. Leah Hurd, wells lead for the Stones project, said the second development well drilled in the field encountered an unexpected tar zone, which made it quite challenging to reach the drilling targets.
The company installed a second drill center because the well trajectories from the first drill center became too complex. “Introducing a second drill center to the field alleviated some of those directional challenges and actually resulted in much shorter well durations,” she said. “Avoiding the tar is what changed the wells from a relatively easy-to-drill field map to something that becomes much more complex and requires a lot more strategic thinking.”
“With extreme water depth, you have high hydrostatic pressure,” Hoffman said. “The hydrostatic pressure at Stones is about 4,500 psi. So that means all of the subsea kit that’s sitting on the seafloor has to be designed for it, requiring increased wall thickness, which in turn increases the overall weight of the subsea structures.”
It also adds to the top tension load, which on this field can be as high as 340 metric tons for the production risers and 170 metric tons for the umbilicals, he added.
Furrows on the seafloor added to the complexity, he said, and required a detailed on-bottom survey. This helped the team place the subsea kit atop the furrows. “That was actually quite unique,” Hoffman said. “Typically the seafloor is benign and physically flat.”
Shell also put vortex-induced vibration suppression systems along the entire length of the pipeline and flowlines in the area of the furrows to prevent fatigue of the lines. To lay the umbilical end termination assemblies and the gas export pipeline inline structure, Shell had to hit the top of the furrows in these vast water depths. “That was a bit of a science project in itself,” Hoffman said. “But we were able to do it successfully.”
There were also issues with the export pipe, he said, when an overstrain occurred at the subsea maintenance valve. “We had to put together a team of individuals, and they worked on it for about 30 days,” he said. “We built full-scale specimens and overstrained the pipe to understand the mechanical properties. After 30 days of intense engineering we determined the pipe was fit for service.
“But it really could have impacted the project. There were challenges along the way, and it’s the way you react to those challenges. The team we had on Stones was fantastic.”
There are several firsts for Stones. In 2,896 m of water, the field came onstream in September 2016 and is expected to produce 50,000 boe/d at peak production.
At these water depths the company has encountered numerous challenges. One of the critical elements was the use of a lazy-wave riser. Hoffman explained the concept: When hurricanes arise in the GoM, an FPSO unit needs to be able to disconnect from the field and get out of harm’s way. But the riser system remains behind. A buoy is used to keep the riser system in place.
“This is the first time in the world that there are steel lazy-wave risers coupled with a disconnectable FPSO [unit],” Hoffman said. “It decouples the dynamic motions of the FPSO [unit] to the touchdown point of the riser so that we don’t over-fatigue the riser at that touchdown point.”
Lohr added that the concept was a joint one between Shell and SBM Offshore. “It’s easy to say 9,500 feet, but it’s pretty difficult to do,” he said, adding that Shell brought its experience using the lazy-wave risers from its BC-10 project offshore Brazil. SBM, meanwhile, brought its experience using the disconnectable buoy technology for the FPSO unit.
“The FPSO buoy is typically hollow steel, and a hollow steel structure will float, but in this water depth, because of the tension from the risers and the moorings that pull on the buoy, SBM was not able to get the steel buoy design to converge,” he said. “You either had to get it so large that the steel wouldn’t float anymore, or it would just implode at depth.”
Using its experience with syntactic foam from the Auger Field, Shell suggested using that material instead of hollow steel for the buoy. “The engineers were hesitant at first,” Lohr said. “But they started doing some design work, and that’s how the buoy turned out. It’s a syntactic foam buoy with syntactic foam blocks inside of a steel frame. There’s nothing new about steel, and there’s nothing new about syntactic foam. But this is the first syntactic foam buoy for a disconnectable FPSO [unit].”
Despite the field’s technical accomplishments, it is the team approach that the Stones folks most seem to extol. “Our vision on Stones is working together to safely deliver our promises,” Lohr said. “That was the vision that I hammered into the team over and over again—I want you to work together, I want you to be focused on safety and I want you to deliver.”
Hurd added that the Stones team has not been operating in a vacuum. “We’ve been taking a global approach to looking at how things are done in different places and seeing if that can be modified slightly to work where we are,” she said.
“It gets back to the ‘grow as you know’ concept. The more you learn about the field, the better you should get at drilling and completing it, and the cheaper the wells should be.”
Currently Stones is in Phase 1B, with the second drill center intact and reservoir study continuing. Once Shell has a better sense of what it’s dealing with, Phase 2 will look at things like EOR.
“We really could not have a larger FPSO [unit] with that kind of technology on it at this point because, again, we’re trying to go with the minimum investment until we know more about the reservoir,” Lohr said. “Future phases may put some additional equipment on the FPSO [unit] or additional equipment subsea. We may do some different things with the well designs. That’s the exciting part of Stones moving forward.”
While it’s early days yet, the success of this project has emboldened Shell and given it a great deal of enthusiasm for the future of deepwater oil and gas production in the GoM.
“It’s quite motivating to see the progression of cost improvements and the learning associated with getting the oil out of the ground,” Hurd said. “It was a fantastic, unbelievable challenge, and I feel like we innovate to make it better every step of the way.”