According to OTEC International LLC (OTI), in 1870, Jules Verne introduced the concept of ocean thermal energy conversion (OTEC) in his book, Twenty Thousand Leagues Under the Sea. Within a decade, American, French and Italian scientists are said to have been working on the concept but the Frenchman, physicist Jacques-Arsene d’Arsonval, is generally credited as the father of the concept for using ocean temperature differences to create power.

“I owe it all to the ocean; it produces electricity, and electricity gives heat, light, motion, and, in a word, life to the Nautilus.” Jules Verne, Twenty Thousand Leagues Under the Sea.

D’Arsonval’s student, Georges Claude, built the first OTEC power plant in 1930 in Cuba, which produced 22 kilowatts of electricity. This led to an on-shore open cycle plant, with a pipe extending out to sea. Despite initial problems, power was generated. French research continued in earnest through the 1940s and into the 1950s. Research also began in California in the 1940s. In all cases, work was slowed or halted by cheaper alternatives to power generation. In the 1960s, J. Hilbert Anderson and his son James Anderson designed a closed-cycle OTEC power plant, aimed to be more practical, compact, and economic. This cycle pumps warm surface water through heat exchangers to boil a working fluid into a vapor. The vapor expands to power turbines and drive generators. Cold water pumped from the deep ocean condenses the vapor back into its liquid state. The Arab Oil Embargo and the skyrocket of oil prices in the mid 1970s drove high interest to the Andersons’ and other OTEC models. Japan and India each have done research on smaller scale OTEC power plants and both continue to pursue the technology. In 1979 and 1980, closed-cycle Mini-OTEC and OTEC-1 were built at the Natural Energy Laboratory of Hawai‘i Authority (NELHA) to demonstrate the concept. The U.S. Department of Energy deemed OTEC was a viable energy source following the Hawaii projects. The Andersons, using personal resources, continued to advance their innovative technology. In 2000, the Andersons granted an exclusive worldwide license to The Abell Foundation to their lifetime work of OTEC research and development. The Abell Foundation established OTEC International LLC in 2001.

OTEC makes use of the vast solar energy stored in the upper layers of the oceans. The concept is based on heat from the warm surface water being used to vaporize ammonia, which turns a turbine to drive a generator to produce electricity. Deep, cold ocean water cools the ammonia back to its liquid state to be heated again in a continuous cycle. OTI has earned an AIP (Approval-in-principle) from ABS (American Bureau of Shipping) for a floating power plant. They are negotiating with the Hawaiian Electric Company for a power purchase agreement that would install a 100 MW offshore power plant in the island of Oahu and a 25 MW facility with the Caribbean Utilities Company, Ltd. A small 1MW power plant will be built ashore in Hawaii to demonstrate the OTEC power cycle functionality before OTI sets up a production floating platform.

 

Liquid hydrocarbon fuels can be produced from associated natural gas via a well-known catalytic chemical reaction called Fischer-Tropsch (FT) synthesis. The FT synthesis is a collection of chemical reactions that converts a mixture of carbon monoxide and hydrogen into liquid hydrocarbons. It was first developed by Franz Fischer and Hans Tropsch at the "Kaiser-Wilhelm-Institut für Kohleforschung" in Mülhei an der Ruhr (Germany) in the 1920s. During World War II, FT synthesis provided the needed liquid hydrocarbon fuels for the German war effort. Later, facing isolation during the apartheid era, South Africa turned to FT synthesis from coal gasification to supply significant quantities of its hydrocarbon fuel needs. Since then, many refinements and adjustments to the technology have been made, including catalyst development and reactor design. The process, a key component of gas to liquids technology, produces a synthetic lubrication oil and synthetic fuel, from natural gas, yet it can also be produced from coal or biomass. The FT process has received intermittent attention as a source of low-sulfur diesel fuel and to address the supply or cost of petroleum-derived hydrocarbons. It is also a process that may allow a substantial decrease in offshore associated gas flaring.

The FT process is a catalytic chemical reaction in which carbon monoxide (CO) and hydrogen (H2) in the syngas are converted into hydrocarbons of various molecular weights according to the following equation:

(2n+1) H2 + n CO → Cn H(2n+2) + n H2O

Where n is an integer. Thus, for n=1, the reaction represents the formation of methane, which in most CTL (Coal to Liquid) or GTL applications is considered an undesirable byproduct. The FT process conditions are usually chosen to maximize the formation of higher molecular weight hydrocarbon liquid fuels, which are higher value products. There are other side reactions taking place in the process, among which the water-gas-shift reaction: CO + H2O → H2 + CO2 is predominant. Depending on the catalyst, temperature, and type of process employed, hydrocarbons ranging from methane to higher molecular paraffins and olefins can be obtained. Small amounts of low molecular weight oxygenates (e.g., alcohol and organic acids) are also formed. The FT synthesis reaction, in theory, is a condensation polymerization reaction of CO. FT synthesis is technically classified into two categories, the high-temperature (HTFT) and the low-temperature (LTFT) processes. The criterion for this classification is the operating temperature of the synthesis, which ranges between 310−340 °C for the HTFT process and 210−260 °C for the LTFT process. An FT facility can be divided into roughly three sections, synthesis gas (syngas) generation, FT synthesis, and refining of the synthetic crude (syncrude).

The FT technology has experienced dramatic improvements in catalyst technology and an aspect vital to fitting the FT reactor and ancillary reactors and equipment aboard FPSOs, has been the decrease in the reactor size and cost. Most of the worldwide capital investment in GTL is being made to build module plants that can fit on FPSOs. There are 2 processes being used; one is the FT process and the other from ExxonMobil, which converts natural gas to gasoline via methanol. General Electric is building a GTL module plant and a partnership between Petrobras and CompactGTL has a working test plant in Brazil, which is scheduled to be installed on SBM FPSOs for pre-salt production, thus beginning to eliminate flaring in Brazil.

With the long distances (around 300km) from the pre-salt plays to the coast of Brazil, the possibility of unloading oil offshore is attractive in comparison to using pipelines for oil transportation. Since the GTL product can be mixed with crude, it greatly simplifies the downstream process and may allow new fields to produce in less time. The Brazil plant demonstrates the world’s first fully integrated small scale GTL facility, at 200,000scf/d capacity, incorporating:

• Gas pre-treatment

• Pre-reforming

• Reforming

• Waste heat recovery

• Process steam generation

• Syngas compression

• Fischer-Tropsch synthesis

• FT cooling water system

• Tail gas recycling

Analysts forecast that this technology will soon be present at the GoM, WA and North Sea and hopefully we will see a drastic reduction in offshore gas flaring worldwide along the next decade.

Sources: U.S. Department of Energy, Petrobras, SBM, CompactGTL, Wikipedia, Biofuels Academy and NSF

 

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As gas flaring becomes more unacceptable from political and environmental viewpoints, oilfields with no viable associated gas solution may be required to curtail production or in the extreme case, cease production entirely.

There is evidence globally that this is starting to occur and proposals for new oilfield projects in remote or deepwater locations must increasingly demonstrate how the associated gas will be processed without continuous flaring. Gas re-injection sometimes offers a solution but this is expensive for deep wells and not desirable for all reservoir structures. Gas-to-liquids (GTL) processes enable monetization of remote natural gas or other gaseous hydrocarbons by converting them into sulfur-free synthetic crude oil that can be easily transported by tanker. The GTL products can then be used as-is or blended with diesel oils as a fuel with lower environmental impact for transportation and power plants.

Originating from technology first developed at the UK Atomic Energy Authority in the year 2000, CompactGTL,the company that basically introduced the solution, has now introduced new modular GTL plant designs integrated with FPSO’s. This has been achieved through close collaboration with major partners in the upstream sector serving to independently qualify the technology as well as creating a supply chain for commercial plants. In addition, a commercial plant may be capable of handling up to 35% CO2 in the feed gas without additional gas treatment, and in fact uses much of this CO2 for syngas and ultimately syncrude production.

In Brazil Petrobras is working closely with CompactGTL to certify this new concept with the help of the American Bureau of Shipping and they already have a pilot plant in Brazil. ABS has already issued an AIP (Approval in Principal) for the technological concept and SBM will be introducing the system in its pre-salt FPSOs.

A GTL plant converts natural gas or other gaseous hydrocarbons into sulfur-free synthetic crude oil through the following steps: 1. The feed gas is converted to syngas through a steam reforming and partial oxidation process. This requires large amounts of oxygen or air and therefore typically involves a large air-separation unit (ASU). 2. The syngas, consisting of hydrogen and carbon monoxide, is compressed and fed to Fischer-Tropsch (FT) synthesis reactors where it is converted to liquid hydrocarbons. Light or heavy syncrude may be obtained, depending on catalyst temperature and pressure. 3. The product of the FT reaction can be further upgraded in a typical refining unit, which may be associated with the GTL plant.

Sources: CompactGTL, GE and SBM

 

Brazil is the largest country in South America and its oil and natural gas markets have expanded massively in recent years, causing the resurrection of its shipbuilding industry as a bonus. The challenging deepwater development projects have high priority in investments both is subsea technology for deepwater field development and onshore and offshore logistics infrastructure.

In recent years Brazil has experienced rapid growth in the petroleum sector. O&G production went from 1.5 million barrels per day in 2001 to 2.4 million b/d in 2010. Offshore production accounted for almost 90% of this figure in 2010. Yet there have also been large onshore natural gas discoveries, which means that the onshore gas market development is still significant and has a strong potential, specifically along the Amazon Basin and a few other Onshore Basins in the north.

Production growth is expected to be reaching levels of nearly 5 million barrels + per day around 2020. This growth is forecast to mainly come from the pre-salt discoveries in the Santos basin, beyond 2020 is anyone’s guess. Petrobras as state controlled national operator, is the dominant player in Brazil’s O&G market, operating about 90% of the offshore production in the country. With new rules for pre-salt E&P stating that Petrobras will be the sole operator and will have at least a 30% share of all future pre-salt plays (Including the new Libra field).

Several international oil companies have made discoveries, and privately owned Brazilian oil companies are emerging as key players. Statoil has the 2nd largest operator production in Brazil from it’s Peregrino field. Projects like Golfinho, Marlim Leste, Albacora Leste, and Cachalote (all Petrobras) and Frade (Chevron) have also contributed to the growth in recent years, while the famous Lula field, which for a while was thought to be the biggest field that would be found, has been the first to produce oil from the pre-salt resources.

In 2011 the National Petroleum Agency (ANP) was only forecasting 17.9 billion barrels boe of recoverable oil in the pre-salt.Now with the confirmation of the recoverable volumes of 8 to 12 billion barrels boe from the giant Libra field in Brazil's Santos Basin, the pre-salt explored so far could yield 35 billion barrels boe of recoverable oil, more than double Brazil's existing reserves.

Analysts and geologists alike have said that the total amount of oil in the region could reach 100 billion barrels,yet  that is only considering the three basins where pre-salt reserves have been discovered, all located along Brazil’s southeast coast.

There is still true potential for deepwater pre-salt discoveries along Brazil’s northeast and north coasts, which align beautifully with regions in West Africa where deepwater pre-salt reservoirs have already been discovered, such as Ghana in the north and in Angola’s Kwanza Basin. Pre-salt exploration along the north and northeast coasts of Brazil and northwest coast of WA are only just beginning and no one really knows the true potential in terms of recoverable volumes in these areas. There is no doubt though that large exploration investments will need to be made on both sides of the Atlantic in order to uncork them.

The extraordinary growth of the world subsea market over the past decade and the raising demand for O&G plays in deep and ultra-deep waters to begin production and for the deep and ultra-deep water drilling to continue in Brazil, at the GoM and in WA, has led to the development of a range of new offshore field development and support vessels, including a large new pipelay vessel, currently laying its pipelines along the GoM.

Since 2012 Saipem has been operating the MV CastorOne, it is a ship-shaped pipelay vessel with an overall length of 330 m (excluding stinger) and DP 3 capable. The CastorOne was classed by ABS (American Bureau of Standards) and is also Ice classed, capable of berthing 700. The CastorOne is currently the largest PLSV at sea and is officially classed as a PCV (Pipelay Crane Vessel) and was designed to transit at speeds of up to 13 knot, allowing it to reduce the downtime, usually caused by long transits.

The CastorOne can prefabricate pipe strings 36m long and is capable of laying up to 60” pipes in S-lay mode or up to 36m pipes, with the capability of joining two 18m pipes as an alternative to the 3 by 12m conventional joints, in J-lay mode. With her unique J-lay tower capacity of 2,500 t installed, CastorOne can deploy pipelines and trunklines in water depth down to 3,000 m. The stinger is specifically designed for any pipe diameter and water depth through continuous control of the overbend stresses on the pipe. The MV CastorOne is currently contracted for three projects at the GoM:

• Amberjack Pipeline’s 219-km-long Walker Ridge export pipeline;

• Enbridge’s 60-km-long Big Foot lateral export pipeline;

• Keathley Canyon’s 350-km-long gas export pipeline.

Following completion of that work, the CastorOne will move to the Santos Basin in Brazil to lay Petrobras’ 380km (236 mile) Lula NE to Cabiúnas trunkline to the coast of Rio de Janeiro, in depths to 2,230 meters (7.316 feet). It will be the first major trunkline connecting Brazil's offshore pre-salt plays to the coast.

 

CastorOne Process Video -

 

 

Scientists have developed the first global model that analyses the routes taken by marine invasive species. The researchers examined the movements of cargo ships around the world to identify the hot spots where these aquatic aliens might thrive. Marine species are taken in with ballast water on freighters and wreak havoc in new locations, potentially driving native species to extinction. The research was published in the Journal Ecology Letters.

As Brazil is experiencing a great increase in shipping, mostly due to the ongoing O&G boom spearheaded by huge deepwater pre-salt reservoirs recently being uncorked, this study can be considered of particular importance for Brazilian environmental agencies such as IBAMA, which are responsible for monitoring and controlling present and future environmental hazards which may affect the country’s diverse and fragile ecosystems, both at sea and along the coast and also at inland waterways such as the Amazon River.

The boom in global shipping over the past 20 years has led to growing numbers of species moving via ballast tanks, or by clinging to hulls. Some ports such as San Francisco and Chesapeake Bay have reported several exotic new species arriving every year. Economic estimates indicate that marine invaders can have huge impacts that last for decades. Now, scientists from the UK and Germany have developed a model that might help curb these unwanted visitors. They obtained detailed logs from nearly three million voyages that took place in 2007 and 2008. Scientists mapped the global routes taken by cargo ships over a two-year period, "Our model combines information such as shipping routes, ship sizes, temperatures and biogeography to come up with local forecasts of invasion probabilities," said Prof Bernd Blasius from the University of Oldenburg. While this is a mathematical model, the researchers were able to adjust it by carrying out field observations. They were able to estimate the probability that a species can survive a journey and establish a population in a subsequent port of call.

"It is called ecological roulette," said Dr Michael Gastner from the University of Bristol.

One of the most celebrated examples of an invasive species is the Zebra mussel. They travelled by cargo ship from the Black Sea to the Great Lakes in North America in 1988. The invaders have caused severe economic problems as they have multiplied rapidly, clogging water pipes. At one point, they cut off a town's water supply.

The hazards of invasive ship-borne species in Brazil is not limited to cargo ships, as there are increasing numbers of foreign-built oil rigs, OSVs, FPSOs, drill ships, survey vessels and cruise ships docking in Brazilian ports almost in a continuous basis and both government and academia will be hard put to monitor ballast waters and hulls with this intensive foreign ship traffic along the whole coast of Brazil.

While the growth in cargo carried across the oceans means that the risk of future invasions is severe, the researchers say that tackling the ballast water issue can be a powerful means of mitigation. But Dr. Gastner is worried that economic pressure might prevent ship owners from taking the necessary steps. "There is no single solution that seems to be working on a global scale; different ship sizes have different engineering constraints - and it takes too much time to have the water filtered." "For the shipping industry, even an extra half an hour in port means additional costs and they are trying to reduce this as much as they can," he said.

This study should also serve as a reference for some Brazilian Universities that are researching such matters. There does not appear to be any for of intensive monitoring of foreign ship ballasts and hulls at Brazilian ports, but there is some academic research being done on the matter of Ship-borne Invasive Species by local universities and we will take a look at these in the future.

Sources: Journal Ecology Letters and BBC Online

With the continued increase in deepwater drilling off the coast of Brazil, it is good to see that Petrobras, Brazil’s national operator, will soon have a well containment device ready for immediate deployment in case of a deepwater blowout such as was experienced in the Deepwater Horizon tragedy at the GoM.

According to a Petrobras drilling inspector who prefers to remain anonymous, the Brazilian super-major player believes that their well drilling and completion systems are totally reliable as long as their safety procedures are followed, however, they are taking no chances and have joined forces with other major operators to increase drilling, completion and production safety standards worldwide. After the GoM accident and following recommendations set out by OGP’s (International Association of Oil & Gas Producer) Global Industry Response Group (GIRG) a milestone document was produced, called Offshore safety: Getting it right now and for the long term, which provides implementation updates in each of the three GIRG areas, as well as on mutual aid agreements that transcend companies and borders. The first area is improving well safety another area is related to a worldwide effort in oil spill response technology and efficiency.

Here we’ll look at the GIRG’s second set of recommendations focused on response preparedness, which led to the creation of the Subsea Well response Project (SWRP), a consortium consisting of BG Group, BP, Chevron, ConocoPhillips, ExxonMobil, Petrobras, Shell, Statoil and Total. SWRP has now designed and built a comprehensive capping system, complete with subsea dispersant capability. The first of the four capping and dispersant capabilities is now available to the global industry via subscription to OSRL, the world’s leading oil spill preparedness and response service company. The first capping stack and dispersant hardware was publicly unveiled in March at OSRL’s Stavanger storage base.

As a key partner in the Subsea Well Response Project, OSRL is setting up a new base in Rio de Janeiro to house intervention equipment and represent the project in the region, this new office will be operating sometime this year and will also feature a comprehensive capping system, complete with subsea dispersant capability among other assets for oil spill response and management. The entire system is designed to be readily transportable by air and/or sea from one of the four OSRL-operated strategic base locations in Europe, Africa, South America and Asia Pacific.

This well capping equipment enhances the industry’s capability to respond to a subsea well control incident and can be deployed anywhere in the world in a matter of days.

• Equipment is available for industry use through OSRL

• Transportable by sea and/or air

• The integrated intervention system includes:

1. Four capping stack toolboxes stored in Norway, Brazil, South Africa and Singapore

2. Two subsea dispersant hardware kits stored in Norway and Brazil

SWRP planned the intervention system, which includes the newly designed subsea capping and dispersant application equipment. OSRL owns the equipment and is responsible for storage and maintenance. OSRL will also make the equipment available to subscribers through subscription and a supplementary agreement.

Back in 2009 I asked a good friend of my late father, who happened to be a long time Petrobras geologist, if he really knew the full potential of the pre-salt, after a while he looked up and said no not really, I know there are big fields out there, probably up to 10 billion boe in some reservoirs, possibly much more...

Well, Petrobras kept on drilling and when Libra was found northeast of the Lula field (5 to 8 billion barrels boe), in 2010, the expectations ran high. Maybe 3.7 billion boe, maybe 15 billion boe. Probably 7.9, those are the numbers the ANP had in 2010. By May 2011 the ANP was downgrading it to 5 billion barrels boe. By the end of 2012, there were already some rumors circulating that Libra could actually be much bigger than was being acknowledged by the ANP because of new data from test wells and extended well tests in the original play at well 2-ANP-0002A-RJS, located in Block SS-AP1.

The ANP has now confirmed that their most recent 3D seismic data, which was acquired shortly before the 11th round of bidding, (that happened last week), shows that the Libra field is massive, much larger than the largest estimate, and that the main reservoir has a column of 326.4 meters containing light oil rated at 27º API. These latest figures peg Libra as containing a whopping 26 to 42 billion barrels boe, of which the ANP expects 30% to be recoverable, this leaves the recoverable oil figures at 8 to 12 billion barrels boe.

At this point Brazil has around 15 billion barrels boe of proven reserves and another 15 billion expected reserves, when counting all the pre-salt and post-salt. With the new number for Libra, the final figure will possibly triple. Libra is located northeast of the Lula field in an area of around 1,500 square km, (which is about 1% of the total pre-salt area in southeast Brazil). The Libra field is around 180km from the coast of Rio.

This really shakes up the O&G market, not only in Brazil, but the World market itself and the ANP has already confirmed that the Libra field will be in the next round of pre-salt bidding and has actually anticipated the bidding round to October 2013 in place of the natural gas bidding round that will now be in November. That shows the magnitude of this reservoir and there is no doubt that there will be a vicious dispute by operators to acquire it, even with Petrobras being the operator with a minimum of 30% shares. This is also a deepwater play, with the main well at over 1,900 meters. This also highlights the fact that there is no estimate for the total potential for reserves within the known pre-salt area. There is also the fact that the whole pre-salt are along the Brazilian coast is unknown, even the extent of the Santos Basin itself is unknown and that there is still a good possibility to uncover pre-salt reservoirs along Brazil’s northeast and north coasts.

Libra Prospect Map (Base Salt Depth)

Azimuth Thrusters have been propelling deepwater drillships for a number of years now. Not only do they propel the drillships from ports to their drilling stations but also undertake the vital task of maintaining the ship’s position during drilling operations. As most people know deepwater drillships do not anchor but maintain dynamic positioning through the use of groups of thrusters.

Depending on the size of the drillship, these may be grouped in threes or fours, and are always positioned fore and aft on traditional drillships. These dispositions vary in semi-submersible drillers and cylindrical drillers such as those developed and used by Sevan Drilling. In both cases the thrusters are used to propel the rig and for dynamic positioning during drilling operations, therefore large reduction ratios and big slow turning propellers are preferred by major thruster manufacturer Rolls Royce, to give maximum thrust to the ships.

Rolls Royce is is currently the world leader in the supply of drivers for drillships, with about 70% share of this market. The drillships operate mostly in O&G wells located on the coast of Brazil, on the west coast of Africa and the Gulf of Mexico. With Brazil currently being the location where most deepwater drillships are in operation and where most new drillships being built are headed to.Rolls Royce has very recently been awarded a contract to supply its underwater removable thrusters to Transocean a world leader in deepwater drilling, it’s notable that this was the 100th drillship to feature Rolls-Royce propulsion.

The robust, heavy-duty Rolls Royce UUC azimuth thruster specifically designed for extended operations on offshore rigs and drillships is capable of underwater mounting and demounting without the need to drydock using a specially developed lifting technique, and a unique sealing and locking device.

There are two alternative ways to connect the lifting wires: Connecting inside the ship to the thruster flange or externally to the lifting lugs on the thruster flange. The former is typical on the drill ships and the latter on the Semi Submersibles. These models come in a power range of 3,000kw to 6,500kw. This is a significant advantage as it greatly reduces downtime since a faulty thruster can be removed and a replacement installed in a matter of hours, if a replacement is at hand.

Even with no replacement immediately at hand it would still take much less time for a replacement to be shipped from the warehouse to the drilling location, than to have to bring the drillship to drydock and back. This, along with robustness and a proven track record of reliability, is the main reason that it is highly probable that all drillships to be ordered by Petrobras in the near future will be using these Rolls Royce UUC thrusters.

Marine Magnetics Corp from Markham, Ontario has successfully tested an AUV-towed Magnetometer. According to Doug Hrvoic president and owner of Marine Magnetics Corp, a company specialized in researching, developing and manufacturing marine magnetometers, OceanServer’s Iver2 AUV model was chosen for its design.

“The Iver2 was designed to enable the integration of various sensors by a third party, and without direct involvement of the Iver developers,” says Bob Anderson, president of OceanServer Technology. “From a hardware standpoint, one approach has been to tow a sensor in the water column behind the AUV, and to connect a tow cable/electrical interface cable to a rugged, waterproof connector on the back of the Iver antenna mast.” That connector provides power and a serial communications port to the vehicle CPU he says.

Working in partnership with Massachusetts-based AUV manufacturer OceanServer Technology Inc., allowed an innovative approach to seabed surveys. The idea was to tow a small efficient magnetometer closely behind an AUV—the thinking was it should reduce the need for weather-dependent traditional boat-towed magnetometer arrays. Marine Magnetics’s Explorer magnetometer had been designed for towing behind a boat, so some adjustments first had to be made such as modifying the housing. “We customized the magnetometer to make it neutrally buoyant and other things that you don’t do for a normal marine survey,” he says. “Normally it’s designed to be heavy so it sinks. Also we added some balancing weights so we could adjust trim to make it an easy load behind the AUV.”

With the hydrodynamics and connectivity challenges taken care of, the crucial question of electromagnetic interference came next: the towing distance was just five meters aft of the AUV. So the next step would be to collect data under real conditions. “I had a really good data set that we could use to truth and check the quality of the data from behind the AUV,” says Hrvoic. “And also the magnitude of the error that the AUV might be creating, if any.” Hrvoic’s data set was from the bed of Lake Ontario, which was an ideal testing ground because of its extensive non-magnetic sediment cover, making for magnetic gradients on a smooth geological background. Man-made objects show very clearly against it. Thus any error in the magnetometer data should show up precisely. Iver2-collected Explorer magnetometer dataset, showing two large steel water intake pipes over a smooth regional gradient background. The survey track is shown as a solid black line. The uniformity of the regional gradient illustrates the high accuracy of the data, showing no signs of heading shifts or motion induced error. Several small magnetic targets are clearly visible and can be correlated with the simultaneously collected side scan sonar data.

This partnership between Marine Magnetics and Ocean Server promises to be an interesting option for shallow water seabed mapping, especially when correlated with side-scan sonar data. I would be interesting to test this concept in deep water, using a deepwater AUV towing a deepwater capable magnetometer. I can immediately think of some good places to use this for shallow and deep water in Brazil, but this is an obviously useful concept for many shallow water locations anywhere in the world. The concept was first tested in Lake Ontario during a reasonably severe storm that included 2 meter waves, so it's definitely usefull and lakes and certainly for rivers and rivermouths too.

Sources: Marine Magnetics Corp., OceanServer Technology Inc., and Earth Explorer Iver2-collected Explorer magnetometer dataset, showing two large steel water intake pipes over a smooth regional gradient background. The survey track is shown as a solid black line. The uniformity of the regional gradient illustrates the high accuracy of the data, showing no signs of heading shifts or motion induced error. Several small magnetic targets are clearly visible and can be correlated with the simultaneously collected side scan sonar data. For example, the anomaly at around 641475E 4839125N is visible in the side scan record as a small partially buried anchor.

Explorer Magnetometer and Software

Use of AUV-towed magnetometers could reduce costs and time to complete seabed surveys, with improved accuracies. Pictured here is the Iver2 AUV with the Explorer Magnetometer rigged to be towed.