Handling gas will become one of the dominant themes of offshore development over the next 5 to 10 years, while deepwater concepts also take their place on the technical horizon.

If coal fueled the 19th century, and oil was the fuel of the 20th, gas is destined to be the fuel of the 21st, said Jeroen van der Veer, president of Royal Dutch/Shell and vice-chairman of Shell's committee of managing directors.

"Since 1970, global gas consumption has doubled. And according to Shell scenarios, over the next 20 years, it could more than double again," van der Veer told a Qatar gas conference in London in September.

In the Middle East alone - which boasts 36% of world gas reserves - the region held only 9% of global gas production in 2001.Total gas consumption in the Middle East in 2001 was 7.062 Tcf (200 Bcm), a 7% rise over the previous decade.

But the Shell boss also points out that gas exports grew over the same period tenfold, from 105.93 Bcf (3 Bcm) in 1990 to 1.094 Tcf (31 Bcm) in 2001.

He talks of liquefied natural gas (LNG) and gas-to-liquids (GTL) technologies where new models of supply will mean more mobility for transporting gas reserves. Shell has boosted its shipping capacity by ordering four new LNG carriers to cater to this predicted global gas boom.

Meanwhile, the British-based BG Group is turning its attention to stranded gas and has invested US $5 million on research in gas-to-solids (GTS) technology. BG and technology partner Advantica believe GTS is viable for converting stranded offshore gas into cash, as an alternative to flaring and/or re-injection.
The companies are working to commercialize GTS within 5 to 6 years, which involves deploying GTS processing equipment as a separate process train on an existing offshore facility, or a separate process barge.

Advantica and BG describe the process simply as mixing gas with water and stirring. Forming gas hydrate involves using screens and hydro cyclones in a first stage process to maximize the ratio of gas to water in a compound. A second "vigorous" stage of mixing removes virtually all free water, resulting in the production of a dry, white, snow-like substance containing 150 times the volume of gas per unit of volume of hydrate. This is capable of being pumped pneumatically - by air. BG and Advantica suggest standard bulk carriers or detachable barges could transport it. Furthermore, the gas put into the process requires minimal processing.

Alternatively, gas hydrate slurry can be produced with less than 50% water content, which requires a bulk separator to produce it. Gas passes through a series of continuously stirred tank reactors at pressures of between 60 and 90 bar, at a temperature between 10°C and 15°C. At this temperature, the gas reacts with water, producing a slurry (the consistency of wallpaper paste) with 75 times the gas volume per unit of volume of slurry.

Is it viable? Yes says BG and Advantica, after constructing a 1-tonne processing package to prove the technology. Shipping requires a carrier to transport the slurry at between 2°C and 3°C at a pressure of 10 bar.

Looking at the economics of the process, BG - in a paper to the Offshore Europe conference and exhibition in 2001 - suggested a cost of $2.6/MMBtu for transporting 200 MMcf/d over a distance of 1,250 miles (2,000 km).

"For regions lacking gas infrastructure, these economic models indicate hydrate GTS technology as the lowest cost transportation technology..." BG says. But it concedes that it would only have a niche application; with larger volumes and longer distances to transport to market, pipeline or LNG economics become more appealing.

Deepwater projects attract attention

Larger developments in deepwater, typically without infrastructure, are attracting the attention of the offshore design community. With ship-shaped floating production facilities now possible in principle in the US Gulf, a joint industry project is looking at a dynamically positioned floating production, storage and offloading (FPSO) concept for ultradeep applications from 8,200 ft to 10,000 ft (2,500 m to 3,050 m) of water. Based on two hull sizes, with storage for 1 million bbl and 500 million bbl, the project aims to create a design as reliable as a moored spar, with discussions already under way with the Minerals Management Services over hurricane-induced emergency disconnection scenarios. A report on progress is planned for OTC 2003, and the project is being managed by Izar's Fene shipyard in Spain, with support from DNV, Marin and FMC Sofec.

"Fuel consumption will be very low," promises Joaquín López Cortijo García, concept engineering manager at Izar Fene.

For BP, some of the key questions for the development of offshore technology over the next 5 to 10 years concern deepwater systems and tools.

Dave Brookes, team leader for BP's deepwater technology unit at Sunbury in the UK, says key marine technologies for his company over the next 5 to 10 years are tied up with subsea processing and flow assurance.

"For deepwater facilities ...the most important emerging technologies are subsea processing and advanced hydrate and wax conditioning system[s] for distance flow assurance," says Brookes.
Dave McKeehan, senior vice president at Intec Engineering, Houston, largely agrees.

With the caveat that most projects now involve industry firsts, you'll need a tall periscope to spot the top emerging technologies, he says. McKeehan picks three technical areas currently under development that will have significance for the offshore sector in future: multiphase metering, remotely operated vehicle ability and large-diameter steel catenary risers (SCRs).

"The first use of a subsea multiphase allocation metering is allowing three operators with 10 wells to share a common flow line in the Gulf of Mexico, thus improving the commercial viability of marginal or smaller fields," McKeehan explains. "As a result, the operators are sharing expensive assets, such as deepwater flow lines. In the broader sense, liquids management of large-diameter, long-distance gas flow lines is a core technology to future long-distance subsea tiebacks in the 50-mile plus range."

McKeehan also identifies survey sensors and positioning equipment mounted on ROVs capable of locating chair-sized objects as key for future marine operations. "This survey technology helps reduce pipeline routing risks, particularly in exceptionally rugged areas. The technology is advancing rapidly and now includes autonomous underwater vehicles as an optional sensor platform."

Turning to large SCR designs, he comments, "While this technology was first demonstrated in 1993, the industry trend is to larger diameters. This technology is an important component of any deepwater development."

But is technical progress fast enough? For McKeehan, this is a supply and demand issue. "In general terms, the pace of development seems well-matched with need. The market demand for secure, safe gas transportation may create new needs in the design of large-diameter pipelines and LNG transport. One area that could use an increase in the pace is the implementation of full-scale testing of single-point suspension risers, such as SCRs. The empirical knowledge base in the vortex-induced vibration (VIV) response of such risers is based on smaller diameters, as compared to ones currently being designed."
Most required technologies are already under development, but a marine-specific issue for McKeehan is progress on autonomous and telemetry buoys for power applications, well operations and flow management to long-distance subsea wells.

"Industry has used such buoys on a very limited basis, and they are showing the promise of reducing the dependency on long umbilicals in subsea tie-back production schemes. In the longer term, we expect a 100-mile (160-km) tie-back in the 10,000-ft (3,050-m) water depth to become the record-setter in the next decade. In parallel, the advances in understanding liquids management can help with this objective, but the incorporation of discrete power [and] control points along the flow line will probably be required in any event."

Work is already under way to turn some of these offshore technology dreams into reality. Scientists and engineers in Norway are working on the next generation of subsea processing system, which is aimed at deep and ultradeep applications.

Processing

Offshore Norway, Troll C saw the first use of a subsea processing system in a water depth of 1,115 ft (340 m) where ABB's Subsis concept - subsea separation and injection system - proved itself viable. Now a Subsis successor is intended to take subsea production further forward.

NuDeep is meant to become the next generation of subsea deepwater processing equipment. At this stage, NuDeep is a research and development project only, but it is geared towards a depth of 10,000 ft (3,050 m). NuDeep comprises four components: a wellhead and completion interface, a wellstream pressure containment system, a two- or three-stage seabed processing system for removal of sand and solids, and an installation and intervention element.

Timing for development of NuDeep suggests elements of the system could be put out for tender by the end of this year with a market launch in 2003. Realistically, we could see a NuDeep facility installed within 5 years. ABB promises much from its research. "The NuDeep technology will open the deep and ultradeep water frontier, moving today's projects that are uneconomical and not technically feasible to develop into the economically viable range."

Hydrogen

Over the next decade, attention is bound to turn to further possibilities provided by energy production from hydrogen.

Already, the European Union has founded a research program into the potential of this energy source. EU research commissioner Philippe Busquin has backed the establishment of a high level group looking into hydrogen energy potential, which has been hailed as a "clean energy source" capable of powering everything from cars and generating plants to mobile phones. The European initiative will seek to "foster development of hydrogen and fuel cell technologies," the EU said. It will draw on experts from leading European research centers, and from fuel cell producers and component manufacturers. Energy companies and utilities are being called on to contribute to the EU program, which will also aim to develop a hydrogen technology research strategy and to look at possible applications.

Shell is already taking hydrogen fuel cell technology seriously by promising to set up a test plant to power a platform offshore Norway by 2012.

Shell's revealed its plan at the Offshore Northern Seas (ONS) conference and exhibition in Norway in August when Shell Technology Norway won the prestigious ONS innovation prize for its solid oxide fuel cell. This could replace offshore gas-fired turbines, and although the ONS prize was for a proof-of-concept cell, its implications are enormous. With Norway's strict environmental regime, demanding the lowest possible CO2 emissions, it was perhaps the most likely location for this kind of development and deployment.

Shell suggests a fuel cell could be twice as efficient as a gas turbine, but with the added benefit of no CO2 emissions - and for Norway, that is the key factor.

"Our ultimate goal is to put a 10- to 20-MW fuel cell on an offshore platform by 2012," said Andrew Grundy, managing director of Shell Technology.

Shell's Draugen facility in the Norwegian Sea could be selected to provide a test bed for fuel cell power generation.

But before that goal is attained, Shell is aiming to build a 250-kW power plant at Norway's Kollsnes gas terminal by 2004, under Norway's Demo 2000 project, which funds technology research. Over the past 3 years Shell Technology Norway has invested $13.5 million (NKr 100 million) on the Kollsnes test. While the fuel cell for this project is being produced in Pittsburgh for delivery next year, the cell could also be produced in Norway in the future.

Since an average offshore installation requires between 10 and 20 MW of power, the energy output from a fuel cell would have to be significantly increased to attain the required level of power by 2010.

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