Petrobras’ FPSOBR is one of two non ship-shaped hull concepts that was granted Approval in Principle by ABS. (Image courtesy of Petrobras)

These are exciting times for innovators in the oil and gas industry.

The depth and breadth of technology development under way today exceeds anything the industry has seen in the past, and more of the R&D projects in the works are collaborative efforts that team not only the different sectors of the industry, but include universities, government agencies, and other high-tech industries.

Though there has been progress across the board, some of the most interesting projects deal with riser technology, floating production, arctic operations, high-pressure/high-temperature (HP/HT) environments, subsea production and processing, flow assurance, and integrated operations (IO).

Reaching deep

In 2003, the American Bureau of Shipping (ABS) certified the use of aluminum alloy for risers (AAR) for Noble Drilling. Since that time, risers made of this material have been deployed on vessels in the Gulf of Mexico (GoM) and offshore Brazil. The industry is now testing deployment of ultra-deepwater AARs that can be installed in 10,000 ft (~3,000 m) water depth. Finding a cost-effective way to use composite materials is one of the industry’s goals. Improving riser design and performance is another.

Companies like 2H Offshore, Acergy, Aker Solutions, and Technip are investing in R&D efforts targeting a range of subjects, such as riser integrity monitoring techniques and data processing methods, vortex induced vibration fatigue responses (particularly in the GoM, where loop currents are a concern), fatigue monitoring, deepwater applications (including new installation techniques), weight optimization, and integrity monitoring.

The Research Partnership to Secure Energy for America (RPSEA) is also funding a number of projects that target riser technology. Two such projects are being led by Tejas Research & Engineering. One is investigating fatigue performance of high-strength riser materials subjected to sour environments, and the other is researching issues related to extreme reach in ultra-deepwater applications. A third RPSEA-funded project incorporates technology from the robotics industry.

Extending the reach of floaters

R&D experts have introduced a number of innovative production system concepts this year, and additional funding is going into systems that can produce in ultra-deepwater and arctic conditions.

Technip, for example, introduced a drilling and production spar in 2008. The new unit is a three-deck spar with a drill set on top. Where the hull in a traditional spar is empty, the drilling and production spar houses circular bulk storage and mud tanks.

Versabuoy International has also designed a floater that uses spar concepts. The new production platform system consists of articulating spars. Connecting the platforms together creates a floating, moveable mass that is fairly inexpensive to construct and mobilize. The length of the spar keeps heave to a minimum, while the articulating joint absorbs wave energy.

The American Bureau of Shipping (ABS) has been involved in a lot of the recently introduced concepts and designs that constitute the next generation of offshore installations. Many of the new designs are hybrids of previously proven floating production systems and as such are posing challenges to class societies like ABS.

One of these designs is the MinDOC3, a cross between a semisubmersible and a truss spar, that will be classed by ABS when it is installed for the ATP-operated Mirage field in Mississippi Canyon in the GoM early in 2009.

ABS also has reviewed two non ship-shaped hull concepts proposed by Petrobras: the MonoBR and the FPSOBR. Both designs were awarded Approval in Principle three years ago. Today, the MonoBR, a short cylindrical mono-column floater, is being considered for use offshore Brazil and in the GoM.

Another spar design introduced this year is the Arctic Spar, developed by FloaTEC LLC. Apart from the arctic winterization of the various parts of the hull, the Arctic Spar is essentially a classic spar with an ice breaking cone at the water line. The unit is designed to withstand ice loading up to a particular limit and to disconnect and move off station once the limit is reached.

Model testing has been carried out on a number of these new floating production systems, but none has yet proven its mettle in the field.
Into the ice

The Arctic is the next frontier for oil and gas production, and it will offer extensive challenges for engineers responsible for designing safe and efficient systems for extreme conditions. The industry is embracing this challenge.

The Research and Maritime branches of Det Norske Veritas (DNV) are carrying out field programs and desk studies on global ice loads for floating production, storage, and offloading vessels (FPSOs) and drillships.

Earlier this year, the opportunity arose to join an ongoing field program that involved the Norwegian Coast Guard vessel KV Svalbard. Working concurrently with the Ice Load Monitoring program managed by DNV Maritime, the project evaluated parameters for an extended station-keeping field program.

In February, the vessel began testing in Norway. Ice loads and vessel parameters were measured in stationary ice at very low speeds. While keeping a constant speed presented problems, it was decided that constant power would be used while the vessel speed was continuously measured. Global loads were back-calculated from actual thrust measurements. The parameters for the KV Svalbard were then transformed into scaling factors for typical FPSOs, with adjustments made for bow shape and vessel dimensions.

Actual ice thicknesses and properties were measured in situ, so effectively this represented a model test at 1:2.5 scale with real ice, as opposed to an ice tank test at 1:30 scale with model ice.

Plans are in place for additional tests to be carried out next year under typical pack ice and ridged ice conditions.

Meanwhile, ABS and the Russian Maritime Register of Shipping (RS) have initiated a joint training program covering surveying of Arctic liquefied natural gas (LNG) carriers for a team of surveyors drawn from both societies. Classroom instruction in early October in St Petersburg, Russia, will be followed by a prolonged period of field training.

Another ongoing study includes ConocoPhillips, Sovcomflot, and Samsung Heavy Industries (SHI), companies that are jointly participating in a pioneering study measuring the effect of ice loads on Arctic class shuttle tanker performance.

The joint project, which ABS said is the first of its kind, will provide researchers with data regarding stresses the vessels experience operating in ice-covered waters.

The study will be conducted on the 70,000 dwt Shturman Albanov, the third in a series of Arctic shuttle tankers scheduled for delivery from SHI in Feb. 2009, during its initial two winter seasons operating in the Barents Sea. A monitoring system will employ fiber-optic sensors within the ice belt at two locations in the bow and stern to measure and record ice pressures and loads and compute ice-induced responses of the hull structure.

Dealing with extremes

HP/HT conditions introduce hazards for operators, particularly in shallow-water deep-shelf wells in the GoM. Considerable time and effort are going into developing equipment that can safely work under HP/HT conditions.

One recent advancement is FMC Technologies’ enhanced vertical deepwater tree (EVDT). The EVDT is designed as a slimbore completion system with a tubing hanger that is small enough to pass through a 135⁄8-in. blowout preventer (BOP) stack. This translates to a single product that can be used in a wide range of applications, from typical deepwater subsea placement to shallow-water jackup depth and new deepwater surface BOP applications. The EVDT also incorporates a retrievable flow module that houses a subsea flowmeter.

The present version of the EVDT, rated for 15,000 psi, will soon be working in a number of fields, and FMC is already working on the next generation of the tree, which will have a higher psi rating and will be even easier to install.

A number of operators as well as system and service providers like Cameron are funding research on the subject of high integrity pressure protection systems (HIPPS), which make operations safer in high-pressure environments. HIPPS is a safety instrumented system that protects lower pressure rated pipelines and risers from overpressure. A HIPPS allows a new high-pressure field to tie in to existing lower-pressure-rated infrastructure and can facilitate development of deepwater discoveries by reducing the operating pressure of flowlines and risers.

In addition to these projects, RPSEA is funding a graduate student design project at Rice University that will investigate design of extreme HP/HT subsurface safety valves.

Making strides with subsea systems

A number of companies are taking a systematic approach to solving subsea production and processing problems as well. One example is a recent project undertaken by Aker Solutions.

The growth of hub-and-spoke subsea production has introduced a need for long subsea transportation lines. Gas being moved subsea presents problems, and Aker Solutions is working to resolve some of them. One of the company’s initiatives is a subsea gas compressor, which is being added to Aker Solutions’ subsea booster family. A modular compressor pilot unit is being built for potential use on the Ormen Lange field offshore Norway. Upon its completion, anticipated for 2010, the 700-metric-ton compressor unit will be disassembled and shipped to the Nyhamna terminus of the Ormen Lange subsea pipeline, where it will receive extensive environmental testing in a seawater-filled pit for two years. With success, a commercial full-size unit consisting of four compressor trains capable of moving both gas and condensate will be built and installed on the seabed 75 miles (120 km) offshore.

FMC has won awards over the past 18 months for several new types of subsea systems. One noteworthy contract, awarded by Total in January, is for the Pazflor project in deepwater Block 17 offshore Angola, which calls for the first subsea separation systems in deepwater West Africa. Deliveries will begin next year for three gas-liquid separation systems, 49 subsea trees and wellhead systems, three four-slot production manifold systems, production control and umbilical distribution systems, gas export and flowline connection systems, and remotely operated vehicle tooling.

Moving hydrocarbons subsea

The increasing number of subsea and deepwater developments brings new challenges where there are no surface connections to the pipeline available for pipeline testing and pre-commissioning. Once subsea and deepwater systems are built and installed, they have to undergo pre-commissioning and commissioning operations that include initial flooding, gauging, testing, and startup. Providing these services in shallow water and topside-to-topside developments is routine, but providing the same services at water depths greater than 3,000 ft (~1,000 m) poses a lot of challenges.

One of the biggest risks is making and maintaining the connection between the vessel and subsea unit. Today it is possible to flood, gauge, and hydrotest a deepwater pipeline without using any down-line. BJ Process & Pipeline Services has made headway in applying this technique on many pipelines, but as systems go deeper, the challenges grow.

BJ is developing a means to remotely close valves at the discharge end of pipeline being tested. Another project in the works is investigating ways to improve pig detection for both launching and receiving, which will remove the need to “over-pump” during subsea pigging operations. A third development is a means of transmitting real-time test data to surface using acoustic telemetry, a process that was in field trials in mid-2008 and one the company plans to make operational soon.

According to John Grover, in a presentation made earlier this year at the Subsea Asia Conference, next up will be finding a way to combine remote valve closing and remote data transmission and guaranteeing a pig location so that risk during deepwater pipeline pre-commissioning can be further reduced.

Researchers at Texas A&M University, meanwhile, are working on flow assurance issues for deepwater LNG transport pipelines, where temperatures can range from 32°F to 35°F (0°C to 2°C). The main challenge in transporting the LNG through pipes is to keep the gas in liquid state without significant boil-off and to prevent potentially destructive deposits. The objective of the new interstitially insulated coaxial pipe (IICP) insulation technology is to reduce the thermal conductance of the pipe. IICP technology uses strategies that attempt to bring heat transfer rates below those of current technologies.

The technology does not use external insulation, making it more durable than foam-insulated products. Additionally, the reduced footprint allows the pipe to be easily transported and installed without additional expenses at the installation site.

Experimental results to date indicate the IICP insulation displays superior insulating characteristics compared to other flow-assurance techniques, which means the technology shows promise for subsea applications. To ensure the best performance in an actual pipe, however, this technology needs to be optimized. Further experimental investigations will have to be carried out to quantify the effects on thermal performance caused by pressure differences between the inner and outer walls and the effect of extreme conditions. Developers of this technology believe the multi-layer all-metal construction will prove reliable when tested under these extreme performance parameters, which means it has the potential to function in some of the industry’s most daunting frontiers.

RPSEA is funding additional research programs, both led by the University of Tulsa in partnership with independent operating companies, that address flow assurance. One project is evaluating flow phenomena in jumpers in relation to hydrate plugging. Another is investigating hydrate characterization and dissociation strategies.

Applying integrated operations

Integrated operations (IO) is another facet of the industry where there are new things happening in rapid succession. One very interesting example comes from Norway.
Earlier this year, major Norwegian stakeholders joined forces to develop a digital platform that manages the risks and optimization of next-generation IO. The joint industry project (JIP), called “IO in the High North,” is a collaboration among the IT, defense, and oil and gas industries. It is supported by the Norwegian Oil Industry Association (OLF), the Business Association of Norwegian knowledge- and technology-based enterprises (Abelia), and the Norwegian Defence and Security Industries Association. DNV is managing the JIP, which aims to facilitate the implementation of next-generation IO by developing a common digital platform.

Oil and gas operations in the high north often entail remote and distributed control of assets ? leading to heavy demands on the communication links and information flow.

Connecting and integrating business processes and information sources across organizational boundaries add to the complexity. And because this region is highly sensitive, a lot of attention is paid to the environmental impact of operations. Heavily instrumented facilities provide part of the solution, but there is generally a need for real-time data transfer among fields and remotely located operation centers.

In the coming four years, participants in this JIP plan to go from conceptualization to industrial implementation. Collaboration, a byword at StatoilHydro, will be vital to the JIP’s success.