Ultra-HPHT, other technologies advance despite oil price drop, but actual deployment in Gulf of Mexico could slow. Bruce Nichols puts it in perspective.
Anadarko’s Lucius Truss Spar, located in 7100ft of water, in Keathley Canyon 875, 236mi offshore in the Gulf of Mexico. Image from Anadarko/Robert Seale.
One question arising from the plunge of oil prices to US$50 from $100-plus is whether the slump will slow development of the ultra-high pressure, ultra-high temperature (u-HPHT) technology needed to produce the deepest recent discoveries in the Gulf of Mexico.
The answer appears to be that any slowdown will be slight, though field deployment – key to long term advances – could slow if prices stay at $50. Lower prices could delay Lower Tertiary projects not yet sanctioned like BP’s Kasks North Platte and Anadarko’s Shenandoah.
For now, u-HPHT technology development is still high on the capital investment to-do list, especially for big companies, and it is likely to stay there barring a more severe price drop, analysts say.
“They remain focused on it, very much so. Oil prices really haven’t impacted that. The technology has really got to work. They’re looking long term. This hiccup is not stopping that,” says Imran Khan, Wood Mackenzie’s senior research analyst for the Gulf of Mexico.
The reason: Unless and until some game-changing breakthrough occurs, “you can’t make new Lower Tertiary projects work at these oil prices,” Khan says. In a recent report, Wood Mackenzie estimated breakevens as high as $70-$80/bbl for Kaskida, North Platte and Shenandoah.
BP is pursuing Project 20K to develop subsea equipment that can withstand Lower Tertiary pressures of 20,000psi and temperatures as high as 350°-400°F. BP has been quiet about progress, and spokesman Brett Clanton declined an update. But he said, “We’re still moving ahead.”
FMC Technologies has had more to say about its efforts, suggesting that the main challenges are solvable by shaping existing materials and tools to the task, developing industry standards for new systems and proving they will work reliably in the field as well as the laboratory.
“The full process involves years, not months,” says Patrick Kimball, FMC Technologies spokesman, but he noted the effort has been underway since at least 2012. Prior to the price drop, FMC Technologies’ estimate was 20k, 350°F equipment would start being installed in 2017 or 2018.
There are challenges that go beyond developing standards and designing and proving new production systems.
Chevron’s Big Foot semisubmersible floating production system on 14 March was towed into the Gulf of Mexico from Kiewit’s Ingleside, Texas, yard, one of six major projects scheduled for startup in 2015. Photo from Chevron.
The Seals challenge
One area is elastomer seals. Existing elastomers meet current wellhead pressure and temperature standards, no more than 15,000psi or 275°F. But it has been hard to find elastomers that tolerate both hotter hydrocarbons and colder seawater at depths of 10,000ft.
“The challenge with those materials is you can either get them to work on the high side or the low side but rarely both,” says Elliott Turbeville, FMC Technologies global materials manager. “When you get above 350°F, it gets even more challenging to even get them to work on the high side.”
FMC Technologies already relies on metal-to-metal seals as primary barriers, but elastomers have been valuable as secondary or tertiary barriers. So the problem continues to be worked, and the company is optimistic a solution will be found soon, Kimball says.
On the metals side, Turbeville says the issue is not to find new alloys that will work. Existing steel and nickel alloys should serve equipment needs. The issue is validating the metals for the more challenging u-HPHT deepwater environments, and testing has thrown some curves.
Agreement on how to do testing, which standards to apply, is as important to industry adoption as the materials themselves. There is a debate over the need to use fracture mechanics as part of a new design code rather than the pressure-based calculations traditionally used to validate designs.
“You need to understand the real fracture toughness of the material in the prescribed environment and you need to determine, based on that fracture toughness and the types of flaws you could have in that material, what the life of that component will be,” Turbeville says.
There aren’t many laboratories capable of doing that, he says. Lots of labs can do it in ambient air. “Our challenge is we need to do it at 400°F with 180,000 ppm of chlorides and high H2S, and that’s where the challenge comes in,” Turbeville says.
One way to withstand high pressures is to build equipment with thicker, heavier walls, but there is a need to keep wellheads, manifolds, flowlines and other components as light as possible so that construction vessels can heft the pieces and install them on the seabed.
Because there are limits on ability to control weight while withstanding higher pressures, more capable construction vessels will be required.
The need for heavier lift vessels
SBM Offshore’s Turritella FPSO will be the second deployed in the Gulf of Mexico for Shell’s Stones development. Images from SBM Offshore.
“Redesign of all of these components is going to have a knock-on effect in terms of the vessels that you need to deploy it, the cranes on board, the things you use to lower them to the seafloor, the rigs,” Kimball says.
There are other metals issues. Operators are seeing unexpected failures in high-strength, corrosion-resistant nickel steels, even in less challenging environments than u-HPHT, and there is a need to overcome that concern, Turbeville says.
In the case of carbon manganese steel, increasing pipe wall thicknesses to withstand higher pressures threatens one of the material’s advantages, field weldability, Turbeville says.
“There may be an opportunity there to develop new alloys that are high strength and highly corrosion-resistant,” Turbeville says. “And it may be we just have to get creative with our engineering of existing alloys to figure out how to use them safely in ways we don’t presently have to do.”
So far, the industry has been able to sidestep u-HPHT issues in Lower Tertiary developments by advancing in increments. FMC Technologies has had a 20k wellhead for some time. Cameron has built a 20k blowout preventer.
The Gulf’s earliest Lower Tertiary developments, Shell’s Perdido, started up in 2010, and Chevron’s Jack/St. Malo, brought online this year, are Lower Tertiary projects whose particular characteristics allowed development with technological advances that were more incremental than revolutionary.
Just because a Lower Tertiary development is u-HPHT at the well bottom in the reservoir doesn’t mean it will present u-HPHT conditions at the wellhead, says Sean Shafer, consulting manager at Quest Offshore Services. Combinations of existing equipment can solve problems.
“There are ways to mix and match,” he says.
Next LT projects in 2016
The next Gulf of Mexico Lower Tertiary projects are scheduled to come in 2016, ExxonMobil’s Julia and Shell’s Stones, and both rely on further incremental advances as well as carefully modulated, relatively small first steps.
Bottomhole temperature and pressure data haven’t been made public, Shafer says, but the two projects wouldn’t be proceeding if they presented insurmountable challenges.
Still, there is caution, he says. Even in manageable conditions, there are uncertainties about the productivity of the Lower Tertiary. There are questions about permeability and porosity and, despite high bottom-hole pressures, projects require subsea boosting to accomplish production.
At Julia, ExxonMobil, which has estimated 6 billion bo in place, is reducing risk by tying back to Chevron’s Jack/St. Malo and initially aiming to produce just 34,000 b/d. Shell estimates Stones has 2 billion bo in place, but will start by producing 60,000 b/d.
More recently, BP, Chevron and ConocoPhillips have joined together to develop the Tiber and Gila discoveries and the Gibson prospect, possibly with a single hub serving all three developments, Shafer says.
“The idea is let’s put something out there that’s a bit smaller, produce from wells, see whether the production profile falls into our assumptions,” Shafer says. “This is really about feeling out the Lower Tertiary.”
Both Stones and Julia involve technological advance, of course. Stones will feature the US Gulf’s second floating, production, storage and offloading vessel with a disconnectible turret system, lazy wave risers and polyester moorings (OE: September 2014). Julia will feature the Gulf’s first high integrity pressure protection system, which is intended to isolate equipment downstream of the wellhead from higher pressures. It is technology proven elsewhere in the world but likely to be important for future Lower Tertiary developments.
Even if oil prices hadn’t dropped, development costs using technology already available had become a big issue. Service companies as well as oil companies like BP, Chevron and ConocoPhillips are teaming up to cut development costs. A recent example: FMC and Technip, have formed Forsys Subsea to increase efficiency of field design and construction and thereby help control costs.
Lowering contractor costs may, in fact, soften the impact of lower oil prices, Wood Mackenzie said in a recent report, making it economical in future years to move forward with developments currently too costly to pursue.
Sampling, boosting advances
Other production technology advances in the Lower Tertiary include the subsea sampling system and single-trip multi-zone frac-packs employed at Jack/St. Malo and the various subsea boosting systems being employed at Perdido, Jack/St. Malo, Julia and Stones.
In drilling technology, Statoil and Chevron are leading the way in trying to commercialize ways to reach deeper targets with fewer casing strings and more control of borehole pressure. Statoil is deploying Enhanced Drilling’s EC-Drill system. Chevron opting for dual-gradient drilling (OE: October 2014).
Statoil has put the EC-Drill system on the Maersk Developer and has employed the system on at least one well, Perseus, which turned out to be non-commercial. Statoil also used the Developer to drill Yeti, where it made a discovery in late April. The Developer moves next to the Thorvald prospect.
Statoil, which has used EC-Drill in shallower water wells offshore of Norway, has declined to discuss EC-Drill’s performance on deeper water prospects in the Gulf. “They want enough time and experience to sort out what it does and doesn’t do well,” says Jim Schwartz, Statoil’s spokesman in Houston.
Chevron has been preparing for months to commercialize its system using the DGD-equipped drillship the Pacific Santa Ana. But so far the company has not discussed results. It is unclear whether the technology was used on the recent discovery at Anchor or a subsequent prospect, Sicily.
While research and experimentation continues in Lower Tertiary technology, development hasn’t slowed yet in the deepwater Gulf’s more familiar Miocene trend.
By the end of this year, six major projects – all tapping parts of the Miocene and-or nearby Pliocene – will have come online, if all schedules hold, Anadarko’s Lucius, Chevron’s Big Foot, ExxonMobil’s Hadrian South, Noble’s Big Bend-Dantzler, Deep Gulf’s Kodiak and LLOG’s Delta House.
Next year, Anadarko’s Heidelberg and Noble’s Gunflint, also developing non-Lower Tertiary geology, are scheduled to come online. Further out, Hess is working toward first production at Stampede in 2018.
Development surge in Miocene
“From a development point of view, this year, we don’t see a slowdown in activity. We see a higher level of spend,” Khan says. “Part of the reason is just the number of projects in the final stages of being brought online.”
And u-HPHT technology is not the only area of innovation. Upcoming 2015-16 projects focus on new ways to increase efficiency and cut cost.
Anadarko is pursuing the design-one, build-two concept with nearly identical spars at Lucius and at Heidelberg, the latter due online next year. LLOG is advancing standardization in development of its Delta House hub and surrounding fields.
In future Miocene activity, Shell is moving forward with front-end engineering and design for its Vito discovery, and BP has filed a long-awaited revised development plan for Mad Dog 2 aimed at reducing development costs.
But how fast those projects become reality depends on the future direction of oil prices.
BP has won regulatory approval for its new Mad Dog 2 plan, featuring a semisubmersible production platform rather than the originally planned spar, but executives have told investors the project probably will be delayed and re-evaluated again.
And future exploration – the necessary lead-in to developments beyond the 2015-16 surge — is less certain. Companies are slowing the pace as a significant number of rigs go off contract this year and next, Khan says.
Both the Baker Hughes and US government tallies of rig activity in the Gulf – though using different methodologies and including both exploration and development drilling – fell by more than 20 in 1Q 2015, Baker Hughes’ to 35, the government’s to 47.
“On the exploration side, our view is it’s likely to plateau or maybe pull back marginally. We’ve had some pretty good years in terms of discoveries the last three years. It’s been a nice uptrend, but we see that plateauing off,” Khan says.