The demand for deepwater solutions remains strong despite the rounds of cuts in capex that have been part and parcel of the overall downturn in project activity.

According to Bob Fryklund of IHS, speaking at a topical luncheon at the Offshore Technology Conference (OTC) titled, “Deepwater Exploration: a View Forward,” “For the last couple of years we’ve been fixated mostly on shale. In some places we say we have shale fever, but deepwater still has a very important role to play.”

By 2040 the industry will need to bring 50 MMbbl/d into production to keep up with demand and to make up for the inevitable decline of existing reserves, Fryklund said.

“We already have some of that in sight in fields that are under development or under appraisal,” he said. “But we need 30 MMbbl/d of yet-to-find liquids. What we have on our charts now is developments that have been sanctioned. They will make up about a third of our requirements for future production, but there are more prospects in the inventory. Most of them will survive even at today’s prices. I know most of you are pricing these out at $60 to $70 a barrel for the next five to seven years. That creates a fairly bright picture for the first 10 billion barrels of our remaining needs, but where are we going to find the next bunch?”

Long-term needs

The industry needs to think about what to do for the long term, Fryklund continued.

“Let me add that the Gulf of Mexico [GoM] also has a substantial role to play. The GoM—particularly in the Tertiary and the Miocene—is feeding the pipelines. This play contributes a much smaller number—about one-fifth of that 10 billion—but it’s still positioned to grow, and there are new plays, particularly the Jurassic, that are just beginning to unfold. Some of the projects are under attack right now because of the downcycle, but operators are starting to think more long term, even looking at breakeven [prices] of less than $60,” he said.

“When we look at some of the companies and look at the unsanctioned projects going out to 2030, you can see that at $60 a barrel, it’s still a broad portfolio. If you look at the band of projects that fall between breakevens of $60 to $80, that’s what most everyone is focusing on,” he continued.

The industry also is going through a period of changes in structure, Fryklund said.

“International operators, which are predominantly the ones involved in deepwater, are cutting their capex, but the cuts range in amount depending on the size of the operator,” he said. “Exxon Mobil is only cutting its capex by about 12%. Those that are a little bit smaller are cutting theirs by about 20%.We’re seeing segmentation occurring within the industry that’s driven very much by asset class. Whether you’re in deepwater, unconventionals or heavy oil sands, we’re seeing a separation based on asset size.”

Ultradeep solutions

With production in water depths of more than 2,744 m (9,000 ft), operators already are hunting solutions for water depths beyond that as well as higher temperatures and pressures and seabed processing needs.

A study by DeepStar was the first major evaluation of 13 alternative deepwater floating platforms and riser systems with dry tree and direct vertical-access (DVA) capability. According to a paper by Rajiv Aggarwal of Granherne Inc. during a technical session titled, “Advances in Deepwater Technology” at OTC, he noted that the participants in the study provided designs for three regions—the GoM, West Africa and offshore Western Australia—and three water depths—915 m (3,000 ft), 1,829 m (6,000 ft) and 2,439 m (8,000 ft). The designs included semisubmersible-shaped and hybrid hulls. Tension-leg platforms (TLPs) and spar hulls were used as baselines for comparison.

The life of the specimen marginal field was 10 years. Reservoirs for the GoM and West Africa were 40 MMboe to 100 MMboe (oil), requiring six producing wells and three water-injection wells. Western Australia’s reservoirs were about 28 Bcm to 85 Bcm (1 Tcf to 3 Tcf) of gas, requiring six producing wells.

Competing designs

Group I consisted of four-column semisubmersible-shaped hulls vs. TLPs. These included a dry-tree design by Aker Solutions, the OPTI-DRI hull design from Exmar Offshore, a damper chamber column hull design by INTECSEA, and a heave-motion and vortex-induced-motion suppressed hull design by Technip.

Group II were hybrid designs, which included the OctaBuoy design by Moss Maritime, the extendable semisubmersible design by FloaTEC and the free hanging solid ballast by INTECSEA.

Group III focused on low-payload DVA designs. The design with compliant vertical-access riser was from Granherne. The OPTI designs from Exmar were evaluated for DVA. A three-column MiniFloat-V from Marine Innovation and Technology also was studied.

Comparative assessments and technology readiness reviews were included in the study. The project confirmed the feasibility of both the semisubmersible and hybrid hull designs as low-cost dry-tree solutions for deepwater marginal fields.

In 915 m water depths, TLP designs are a low-cost option. Offshore Western Australia semisubmersible hulls with suction anchors would be a competitive solution. Novel semisubmersible and hybrid designs showed increased value for water greater than 1,524 m (5,000 ft) deep.

As Aggarawal pointed out, “Some solutions require more work.”

Going with the flow

Other technologies under the microscope include a project aimed at improving flow measurement in deepwater projects, which is paying dividends, according to speakers in an OTC technical session titled, “A Window into Subsea Operations—from 10,000 Feet.”

The project, sponsored by research partnership RPSEA, is looking at technologies including a deepwater sampling system, deepwater subsea sensor and deepwater subsea clamp-on meter.

Chip Letton of Letton-Hall Group said seven independent smaller projects have been brought together under one umbrella to address gaps in deepwater measurement. “We all know that measurement is not the simplest thing to do even if you can get your hands on the meter, but when you put a meter on the seafloor and expect it to last for 20 to 30 years without even touching it, the challenges are great,” he said.

JIP partner input

“The deeper you get, everything gets bigger—not only the impact of the problems but the cost to the environment and the cost to the stakeholders,” he continued. “Deeper water is just more difficult. Measurement is really the only way to understand this. You have really got to have some instruments to be able to understand what is happening on the seafloor.”

Joint industry project (JIP) partners Chevron, ConocoPhillips, GE, Statoil and Total provided funding and expertise for the project.

He stressed the importance of the work, saying that a meter that was not working accurately could fluctuate with readings as much as 2% higher or lower than they should be. That, in turn, could prove “catastrophic,” particularly in high-capacity deepwater wells.

The JIP has investigated a means of being able to clamp a meter onto the outside of a pipeline and use electromagnetic measurements to measure what is flowing through the pipe. Work also is being done to check for subsea kicks by monitoring small changes in the mud density at the bottom of the mud line in wells.

[Editor’s Note: Parts of this article are based on information from SPE papers 26033 and 26059.]

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