Category Archives: Offshore

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The offshore oil and gas sector has over the decades come to be defined by megaprojects with 30-to-40-year project horizons. But the future of offshore development will depend on the industrys ability to find innovative ways to cut costs and slim the capital requirements.

Many examples were to be shared with oil and gas professionals at the 2020 Offshore Technology Conference (OTC) in Houston. However, due to the COVID19 pandemic, this year marked the first time that OTC was cancelled since its inauguration in 1969.

Despite the global disruption, the flow of ideas continues.

As proof, what follows is a curated summary of some of the papers that were to be presented at OTC. They were selected for their focus on emerging technologies and unique concepts that aim to reduce the cost burden long associated with offshore exploration and development. Their state of maturity ranges from proof of concept to fully deployed.

All 2020 OTC papers are available at http://www.onepetro.org.

Among the most dominant technology arenas in the oil and gas industrys digital transformation are fast-emerging machine-learning programs that en-able predictive analytics. This paper (OTC 30782), produced by software developer Spark Cognition, offers two case studies that show how machine learning is being adopted in the offshore sector.

The first involves an unnamed supermajor that was suffering multiple production-impacting events involving the gas system on an offshore facility. Conventional methods failed to pick up the signals of failure. The software company was then tapped by the operator to test an unsupervised learning approach.

Years of historical data were run through the program and reorganized so that irregular data sets could be identified and labeled as anomalies. By flagging the anomalies, engineers knew what to investigate; specific tags were helpful in root cause analysis.

While the solution accurately predicts upcoming asset failure, a significant additional benefit is its ability to identify system or process failure where no particular asset has failed but where a process has become so unstable, the system needs to be shut down and restarted in a controlled manner, the paper reads.

The proof of concept resulted in a full deployment across the supermajors offshore facilities, refineries, and petrochemical plants.

In the second case study, a different oil and gas company was focused on lowering the cost of offshore production by $5/bbl. The initial pilot was selected for an unmanned platform that pumped 10,000 B/D of crude slurry to processing facilities. The facilitys chief source of unplanned downtime was a multiphase pump that would go down for a number of reasons, including seal and filter issues.

After a custom-designed machine-learning program and behavior model were aimed at the problematic system, 75% of known historical failures were detected with 2 to 12 days of warning. The first 6 months of the programs live deployment coincided with the unmanned facilitys longest period of continuous operation. The operator estimates that it gained $500,000 in production value for each day of downtime prevented.

Deepwater well intervention has entered a relative state of maturity over the past decade, providing the subsea sector with untold value by reviving aging or problematic assets. Despite its positive track record, operators continue to avoid subsea well intervention due to the time and costs it requires.

The main cost driver comes from the need to use rigs or specially designed intervention vessels to carry out the delicate task of re-entering a wellbore. Researchers at the Brazilian technology institute Senai Cimatec and national oil company Petrobras think the best way to lower the cost of using these two platforms is to not use them at all.

Instead, let a robot do the work.

In their paper (OTC 30886), the authors describe the creation of a subsea workover robot that consists of two systems: a cocoon that protects, supplies power to, and carries the second system; an intervention unit that moves into the production column laden with equipment and sensors. The roadmap foresees using the intervention robot for a number of workover operations that includes gas-lift-valve exchange and plug replacement.

If such a system were available, the industry could rely on its lightest work vessels for subsea intervention. Importantly, this concept may not even require a vessel to maintain station keeping, which would free it up to perform work on other areas of a subsea field.

Inside the intervention unit is a package of computers and sensors designed to guarantee the precise monitoring of the environment and of the equipment, the paper notes. Among the innovations involved is a self-localization system that uses an encoder attached to the tractor motor and a magnetic sensor that is similar to a casing-collar locator. Other proposed tool capabilities include paraffin cleaning before testing begins and wellbore-obstruction detection.

With the proof-of-concept robot built and tested in both the laboratory setting and a test well, the developers next step is to adjust the design to build a prototype designed for an offshore field test.

Many of the worlds remaining reserves are locked away in what the industry calls marginal fields. Exploiting these fields profitably has proven over the years to be the mother of invention.

One of the latest examples comes from Vestigo Petroleum, whose engineers overcame the economic barriers of marginal oil fields by using a reusable wellhead platform that connects to a floating production, storage, and offloading unit (FPSO). The deployment of this system was a first-of-its-kind project for Malaysia.

Vestigoa wholly owned subsidiary of Malaysias state-owned Petronas Carigaliis producing from a reusable platform at the Jitang field. Discovered in 2016, the field achieved first oil this past Januaryjust 13 months after the final investment decision was made. The field is about 95 miles offshore Malaysia at a depth of about 240 ft.

Vestigo reports a cost of about $24million to build the platform, which is unmanned and remotely controlled from its companion FPSO stationed just over 1,000 ft away. Compared to a newbuild, the reusable platform represents a cost savings of 40%. The speed of project delivery would not have been possible without using a platform designed to be reused with few modifications or additional equipment.

The wellhead platform was relocated from its original host field located about 34 miles away from its current home. Production at the previous field ceased in January 2018 after 3 years. The facility has an expected service life of 15 years, which means at the current rate, it could be redeployed to another three offshore fields before retirement.

The only new pieces of major equipment required to redeploy the platform at its second field were four new flowlines for each of the new wells. In addition to the overall system design, key to making a reusable platform economic on marginal projects is to have a fine-tuned relocation methodology.

One enabling feature in this regard is the suction-pile technology that the platform uses as its foundation. The suction piles allow the platform to be easily pulled up from the seabed without cutting the piles, the use of oilfield divers, or the need to transfer back to an onshore facility for repairs.

To move the facility, a heavy-lift vessel was required along with a one-piece, wet tow. This involves a single operation to lift both the topsides and substructure together, and then tow the partially submerged structure to its new location.

A two-piece, dry tow would have involved separating the two systems and the use of barges for relocation. The latter strategy comes with certain advantages but is overall a more complex operation that would have cost 30% more than the one-piece method. Using the suction piles as a foundation also helps speed the installation process, which Vestigo said takes less than 24hours compared to other methods that take days.

There are two traditional ways to directly measure the downhole conditions of oil and gas wells: wireline logging or permanent downhole sensors. Despite the value of the data, both technologies come with certain complexities, heavy-equipment requirements, and price tags that limit their use.

This drove innovators within Saudi Aramco to come up with a third way that it hopes to use across its prolific oil fields someday.

Called the sensor ball, Aramcos innovation is described in the paper (OTC 30538) as a small, autonomous platform that uses gravity to travel down a wellbore. At a desired depth, the plastic-coated ball releases a dissolvable metal weight to switch its buoyancy from negative to positive.

Once the weight is fully dissolved, the ball floats back to the wellhead where it is plucked out and its data transmitted wirelessly to a laptop or cellphone.

Aramco developed the first prototypes in 2016 at its research center in Houston before running tests of the newest design in a pressurized water well in Saudi Arabia. The company reported that the sensor ball effectively logged pressure and temperature during these runs. The deepest test was about 3,600ft which required a round trip of more than 3 hours.

The innovation is promising but not fully rendered.

Aramco said the margin of error on depth measurements is about 2%amounting to 100 ft of uncertainty in a 5,000-ft deepwater well. Casing-collar location technology may address this shortcoming. A new version is being built to withstand high temperatures and pressures up to 10,000 psi.

This paper (OTC 30595) underlines the importance of using a fine-grained vs. a broad-brush approach to evaluate an emerging technologys market demand. The subject of scrutiny in this study was a hypersonic impact technology developed by HyperSciences, which is partly funded by Shells GameChanger innovation program.

The hypersonic impact-drilling concept creates a borehole by shooting penetrators faster than the speed of sound at hard rock from the surface. This requires the borehole to be on vacuum and is done multiple times to deepen the hole. Thousands of shots would be required to drill a single well.

At hypersonic speeds, the strength of materials is so small compared to the stresses upon impact that both impactor and target are significantly eroded and may be in part vaporized, the paper reads.

Shell, HyperSciences, and a pair of technology consultancies relied on data from more than 60,000 wells from more than 100 operators to help assess the application spectrum of this unique approach. Using this database, a synthetic time-depth curve was built to see where the hypersonic system would remove nonproductive drilling time.

Assuming the technology concept was in a mature state for the past 10 years, the authors asked, what would have been its indicative unrisked commercial value relative to existing technology?

The evaluation model suggested hypersonic impact drilling could save around $4 billion over a 10-year period on more than 2,300 applicable wells. This model also found a potential savings of more than $20 million on half a dozen wells, and after 1,000 wells, the value-creation factor fell to $1 million per well. After 2,000 wells, the savings dropped below $10,000.

In the end, the work also suggested that the technology developer make a pivot to expand the systems application base. This led to the current iteration of the technology which will launch the projectiles through a bottomhole assembly and the drill bit instead of from the surface. The model found that if this could be done, the number of applications for hypersonic impact drilling increases threefold and its value creation jumps by a factor of 3.5.

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OTC 2020 Tech Papers Offer a Look Into the Future of Offshore - Journal of Petroleum Technology

A fire on the idled Terra Nova oil facility that Suncor Energy operates off the coast of Newfoundland & Labrador has been extinguished, the energy regulator for the province said on Saturday, even as the vessel faced an uncertain future.

No one was hurt in the fire, the Canada-Newfoundland and Labrador Offshore Petroleum Board said in a statement. There was no oil or gas held onboard the vessel as it was not producing, the regulator said.

Further details were not available and Suncor could not be immediately reached.

The regulator ordered Suncor in December to shut down Terra Nova, operating in the Atlantic Ocean some 350 kilometres (217 miles) east of St. Johns, after finding that the companys fire water pump system was non-compliant.

Terra Nova has operated since 2002 and can store 960,000 barrels of oil, according to Suncor, which owns nearly 38% of the vessel. Other companies, including Husky Energy , own smaller stakes.

Suncor had scheduled work on the vessel in Spain to extend its life by a decade, but said this month that it had suspended those plans due to the pandemics spread in that country.

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Fire extinguished on Suncor offshore oil vessel that faces uncertain future - BOE Report

Offshore staff

HOUSTON Wild Well Control Inc., a Superior Energy Services company, says it will resume in-person class training for WellSharp Drilling and Well Servicing well control courses on July 6, 2020 in its Houston, Tyler, and Odessa, Texas; Oklahoma City, Oklahoma; Cannonsburg, Pennsylvania; and Casper, Wyoming locations.

Other locations will be opened based upon demand.

WellSharp Live, an IADC-approved distance learning training delivery option will remain available for locations constrained by COVID-19 regulations, the company said.

WellSharp Live was developed as a temporary solution to support ongoing training and learning in the oil and gas industry during the COVID-19 crisis. Nearly 30 classes have been delivered since its inception on May 4, 2020.

Kenny Smith, vice president, Well Control Training at Wild Well, said: While the WellSharp Live option ensures our WellSharp Drilling and Well Servicing well control courses continue to be instructor-led and 100% IADC-accredited during these extraordinary times, we are anxious and excited to get back to in-person instruction with personal interaction and engagement.

06/01/2020

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Wild Well Control to resume in-person training in July - Offshore Oil and Gas Magazine

June 1, 2020

Jack-up rigs - Credit: Jevgenijs/AdobeStock

ONGC has moved 33 offshore jack-up rigs to new drilling locations ahead of the adverse weather conditions associated with the Indian monsoon season.

According to AqualisBraemar, which assisted with ONGCs rig moves, said the operation was completed successfully "despite severe constraints caused by the Covid-19 lockdown in India."

Moving so many rigs to new locations before the onset of the south west monsoon is always an annual challenge, but it was an even bigger achievement this year considering the travel limitations and constraints caused by the Covid-19 lockdown in India, Rodger Dickson, group director offshore AqualisBraemar.

The moves were conducted using AqualisBraemars specialist team of mariners supported by their structural and geotechnical engineers working cooperation with ONGCs in-house rig move cell, AqualisBraemar siad.

Each of the 33 rigs was placed at its respective monsoon locations before the onset of the seasonal adverse weather conditions. Of these, 24 rigs were moved on to or from wellhead platforms and 9 rigs to open locations.

The combined total towing distance for all rigs was approximately 1,900 nautical miles.

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ONGC Moves 33 Offshore Rigs Ahead of Monsoon Season - Offshore Engineer

Little Island in May 2020 CityRealty

The much-anticipated offshore public park in the Hudson River is coming together, with its concrete tulip-shaped pots in place and the firsttrees planted. New photos of Little Island at Pier 55 show construction progressing ahead of its scheduled spring 2021 opening. The two-acre park, designed by Heatherwick Studio and MNLA, is meant to resemble a leaf floating on water, with its concrete basesittingabove the river.

Little Island in May 2020 CityRealty

Funded by billionaire Barry Diller and the Diller-von Furstenberg Family Foundation and run by the Hudson River Park Trust, the park is estimated to cost roughly $250 million. The undulating concrete support structure gives Little Island varying elevations, between 15 and 62 feet.

Little Island will feature four different landscape typologies at its four corners, with rolling hills, walking paths, and lawns, along with 100 species of trees and shrubs. According to the parks website, the first dozen trees, which reach 20 to 25 feet, were planted via craneon the concrete tulip-shaped piles in March.

Little Island in May 2020 CityRealty

Little Island will be a maritime botanic garden with 35 species of trees, 65 species of shrubs, and 270 varieties of grasses, perennials, vines, and bulbs, many of which have been selected for their fragrance and attractiveness to birds and pollinators, Signe Nielsen of MNLA said. The landscape is one of sweeping swaths of textures and seasonally calibrated color themes punctuated by magnificent trees.

Little Island in May 2020 CityRealty

The park includes overlooks at the northwest, southeast and southwest corners of the park, with the latter at the highest elevation point in the park, reaching 63 feet. Little Island will be home to a 700-seat amphitheater, a stage with the feel of a secret garden, and a playground with food and beverage options.

Diller originally proposed a futuristic park at the site in 2014, but opponents of the plan blocked construction fromstarting for nearly three years until the plug was pulled.But after an apparent deal was brokered by Gov. Andrew Cuomo, the plan was revived.

[Via CityRealty]

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New photos show 'Little Island' offshore park making progress at Pier 55 - 6Sqft

New Acidizing Method Improves Stimulation in Deep, High-Temperature Offshore Well

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The complete paper discusses a method of stimulating deep, high-temperature offshore wells by combining an efficient single-phase retarded acid (SPRA) system and an engineered, degradable, large-sized particulate and fiber-laden diverter (LPFD). The method was introduced in a well in the Arabian Gulf, where it helped the operator achieve effective, uniform stimulation.

Treatment of deep, high-temperature carbonate reservoirs such as those in the Arabian Gulf presents a series of complex and related challenges to achieve effective and uniform stimulation. Elevated temperatures and heterogeneous formations in these reservoirs require robust treatment fluids that can withstand the harsh environment to achieve good reservoir contact with an acid system along the entire interval of interest.

Emulsified acids have been the preferred stimulation choice of major operators in this region because of these acids superior corrosion inhibition and deeper penetration into the reservoir. However, using emulsified acid adds to the complexity of the stimulation operation by contributing to higher friction pressures, limiting pump rates, and requiring elaborate mixing procedures that constrain offshore rig-based interventions. Operators are searching for simplified acid systems that can deliver friction pressure similar to that of unmodified hydrochloric acid (HCl) and reservoir contact performance equivalent to that of emulsified acid. Arabian Gulf operators also seek a robust diverter that can withstand high differential pressure at high temperature, enabling efficient treatment coverage of all perforated intervals.

Previous stimulation jobs in the region indicated a need for a significant amount of traditional diversion materials to effectively plug the leakoff zones. To address the challenges, an SPRA and a new degradable LPFD system were introduced to conduct a matrix-stimulation treatment featuring efficient contact with the reservoir, safe corrosion inhibition, and effective diversion in a well with a 320F bottomhole static temperature and a heterogeneous environment with a permeability contrast of more than 100. The SPRA was a 15% HCl-based acid system.

The fluid delivered friction pressures similar to those of unmodified 15% HCl and wormholing performance equivalent to that of emulsified acid without encountering the issues of fluid quality with respect to emulsion stability, and much higher dissolution power than organic acids and chelating agents. The pressure drop after the first acid stage was greater than 1,000 psi in approximately 60minutes. After the second stage of acid, the pressure drop was close to 1,000psi in approximately 30 minutes, achieving an approximately 1,000psi increase of injection pressure across the perforations. Additionally, using the LPFD system reduced the footprint in offshore operations, simplified materials handling, and delivered the most efficient diversion performance in bullhead operations compared with that of other diverters.

The complete paper presents detailed overviews and descriptions of laboratory qualification of the featured SPRA and LPFD approaches. The SPRA overview focuses on conductive channels, including wormholes, and the influence of fluids and injection rates on the dissolution of these channels. These effects can be replicated in the laboratory in cylindrical cores using a coreflow experiment.

An SPRA that was successfully introduced to field-scale applications in Kazakhstan demonstrated a marked improvement over emulsified acid in both wellsite delivery and downhole performance. While previous studies had been limited to wells of moderate temperature, the coreflow experiments for this case study were performed at 325F. The experiments were performed using a Chandler formation response tester. In each test, the backpressure was held at 1,200 psi to reduce or eliminate the effects of CO2 bubbles. The cores used in the experiments were composed of Indiana limestone or Silurian dolomite and have a 1-in. diameter and a 6-in. length. The brine permeability of the cores ranged from 2 to 10 md for Indiana limestone and 40 to 180 md for Silurian dolomite. Permeability measurements were obtained using 2% potassium chloride brine at the experimental temperature.

The results in Indiana limestone showed that the SPRA is as efficient at penetrating the reservoir as the emulsified acid at most injection rates. In some cases, the SPRA is more efficient than an emulsified acid when injected into Silurian dolomite. The complete paper explains the process for the laboratory qualification of the SPRA.

The complete paper also presents an overview and outlines the laboratory qualification process for the new LPFD, which was created to increase acidizing treatment efficiency and performance in wells with challenging conditions such as high-permeability contrasts resulting from large fractures, vugs, or voids from previous acid treatments.

The LPFD is a blend of multimodal fully degradable particulates and degradable fiber. The particulates are larger than conventional diverters for enhanced bridging performance. The largest particulates bridge in a fracture, void, or similar near-wellbore matrix feature, while the smaller particulates accumulate in interstitial spaces to reduce the permeability of the diverter pack. Fibers assist both in bridging and in transport of the particulates downhole without dispersion.

This engineered diverter can plug fractures of up to 12 mm in width and requires a smaller volume to generate the same diversion pressure if measured by the surface pressure change. Preparation and deployment of the diversion pill is easier.

The deployment method was developed to overcome the challenge of pumping large particulates through a conventional positive displacement pump. A high-pressure injector eliminates the issue of moving large particulates through the small gap between the valve and the seat. By eliminating the need for dedicated pumping equipment, the overall footprint at the wellsite is reduced. Additionally, the injector enables the delivery of a highly concentrated pill to the formation and decreases the total amount of diverter pumped without compromising diversion performance.

Laboratory testing and qualification of the LPFD was focused on two areas: determining bridging capabilities of the LPFD and evaluating the length of time the material would persist in the formation at various temperatures before degradation.

The exploration gas well was completed with a 3-in. testing string equipped with memory gauges and 4-in. production liner. Two perforated intervals of 60ft, each near 16,000-ft measured depth, were placed in a naturally fractured dolomite/limestone formation. The bottomhole temperature was approximately 320F, and the permeability contrast between the most- and least-permeable zones exceeded a ratio of 120.

In previous acid treatments in nearby wells using conventional diverter materials (ball sealers, crosslinked gels, and gelled acid), leakoff zones along the target interval were difficult to block, indicating that more-aggressive diversion methods would be needed to improve wellbore coverage of the main treatment fluid. The desired treatment for the well included 171 bbl of SPRA split into two stages separated by a small pill of LPFD.

The complete paper presents a detailed description of the modular offshore stimulation system, job design, and execution. The stimulation treatment consisted of two acidizing stages of SPRA separated by one diversion stage. The volume of the HCl acid in the SPRA stages was equivalent to the dosage used for emulsified acid in previous operations. The stimulation treatment was pumped per the schedule, and the bottomhole pressure was recorded through a memory pressure gauge installed in the testing string. When pressure-gauge data were recovered on surface, a more-complete evaluation of the effect of the SPRA and LPFD was conducted. After the SPRA reached the formation, the bottomhole pressure decreased from 12,800 to 11,650 psi during the first acidizing stage and from 12,520 to 11,510 psi during the second stage. Conversely, after the LPFD reached the perforations, bottomhole pressure increased from 11,550 to 12,520psi, indicating the successful blockage of higher-permeability zones and a redistribution in the flow of treatment fluids to lower-permeability zones (Fig. 1).

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New Acidizing Method Improves Stimulation in Deep, High-Temperature Offshore Well - Journal of Petroleum Technology

The 252 MW Seastar offshore wind farm in Belgium has been connected to Elias Modular Offshore Grid (MOG).

Seastar is part of the 487 MW SeaMade project which comprises 58 Siemens Gamesa 8.4 MW turbines.

The connection of the wind farm marks the completion of the MOG located 40km off Belgiums coast.

The switching platform bundles together the export cables from the Rentel, Northwester 2, Mermaid and now the Seastar wind farms and transports the generated energy to the mainland via a shared transmission system.

It has been operational since September 2019, when it was connected to the Rentel wind farm.

Once all the projects are operational in late 2020, they will generate an estimated 8 TWh per year on average, equal to approximately 10% of Belgiums total electricity demand.

The federal government has also begun developing a second-generation area for offshore wind power, which will boost the installed capacity in the Belgian part of the North Sea 4 GW by 2030.

The connection of the last wind farm is a major milestone both for the Belgian offshore wind sector and for Elia. However, our work in the North Sea is far from over. We have started designing a new offshore power hub that will serve as a key link in the second generation area currently being developed, said Chris Peeters, CEO of Elia Group.

We also need to modify the onshore high-voltage grid to ensure that we can transport increasing volumes of electricity generated offshore to consumers, which is why Elia is working hard on the Ventilus and Hainaut Loop projects in the provinces of West Flanders and Hainaut respectively.

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MOG Completed as Seastar Connects - Offshore WIND

When Ohio recently approved construction of a wind farm in Lake Erie, the first ever freshwater offshore wind project in North America, the developers were shocked.

The approval by the Ohio Power Siting Boardincluded conditions that the developer,Lake Erie Energy Development Corporation (LEEDCo), says will essentially kill the project. The turbines must be shut down at night for eight months of the year, from March to October, to protect birds and bats.

LEEDCo, apublic-private, non-profit partnership,has pushed for years to build an offshore wind project, called Icebreaker Wind, in Lake Erie, about eight miles from downtown Cleveland.

The project proposesto build six wind turbines, producing more than 20 megawatts of energy, enough to power about 7,000 homes. According to the company, it would create 500 jobs, and more than $250 million in local economic development.

Icebreaker is billed as a demonstration project, and is thus named because it would show whether wind turbines can withstand the force of ice sheets that form on the Great Lakes in winter.LEEDCo hopes to use this project, in the works since 2012, as a jumping off point to build a larger offshore wind energy industry in the Great Lakes.

There are more than 100 offshore wind farms in Europe, but theres only one in the U.S., off the coast of Rhode Island. Among renewable energy sources, wind produced the most energy in 2019, and that came almost entirely from land-based wind turbines. But offshore wind energy is expected to ramp up within the next decade.

The Ohio Power Siting Board (OPSB), which certifies significant new utility projects, like electric generating plants, gas pipelines, and wind farms, recently announced that it approved the Icebreaker project, under the condition thatLEEDCo turn off or feather the turbines at night from March 1 to November 1, and conduct radar studies of birds and bats. Millions of birds migrate twice a year at night over Lake Erie.

Based on the results, LEEDco must come up with a plan to mitigate the impacts. Once that is done, the company could seek approval to run the turbines at night.

But LEEDCo President Dave Karpinski doesnt see this as an approval. He calls the state decision a project killer, a poison pill, and says it makes the offshore wind project unable to be financed.

According to Karpinski, LEEDCo has already provided huge amounts of data and analysis of this issue. It has gotten all other required approvals from state and federal authorities to move forward, including an Environmental Assessment by the US Department of Energy, under the National Environmental Policy Act, or NEPA.

Their environmental assessment found that there were no significant impacts, Karpinski said. The Army Corps has issued its permits for doing work in the water. The Ohio EPA has issued its approval permit.

Also, LEEDCo already negotiated this specific issue with technical staff of the Ohio Power Siting Board. According to Energy News Network, the OPSB staff suggested nightly shutdowns to protect bats and birds in 2018, even though LEEDCo had already reached agreement with environmental groups. LEEDCo negotiated with OPSB staff and the Ohio Department of Natural Resources for months. They reached a compromise last May that dropped the requirement.

So, Karpinski says, he was shocked when the board included it in the final vote.

If you can do all that work and reach these agreementsall these objective people that are paid to do this, and arent biased by interests on either side made that decision, and it was reversed and thats a problem, he said.

The agency defends its authority to make this decision. Matt Butler, spokesperson representing the OPSB said in an email, The Board is not bound by settlement agreements and may accept, reject, or modify settlement agreements based on the case record.

The Black Swamp Bird Observatory, in northern Ohio, and the Washington, D.C.-based American Bird Conservancy (ABC), filed a federal lawsuit in December against the Department of Energy and other agencies. They want a more thorough environmental assessment, and are challenging the government funding for Icebreaker Wind, which has been more than $50 million.

ABC is pleased that Ohio regulators put nighttime limitations on the turbines in their decision. We thought that was appropriate, said Steve Holmer, the groups vice president of policy.There still has not been adequate monitoring or proven mitigation and so it makes sense to take a cautionary approach here.

This has been already identified as a globally significant bird area, he continued. The issue is whether were going to fully, adequately consider wildlife when we make these decisions and in our view, they simply havent. We think that this is just not an appropriate location for wind development.

Other environmental groups, including Sierra Club and the Ohio Environmental Council, support Icebreaker Wind, saying that the developer has shown it will monitor and protect birds and bats, while providing offshore wind power that can offset carbon emissions from fossil fuels that contribute to climate change, and are also detrimental to birds.

Under the OPSB board decision, the offshore wind project is economically un-workable, according to Karpinski. Hes looking into what happened. He wants to know why the Ohio board did not follow the agreement signed by its own staff. Karpinski also points out that its been reported that Murray Energy, a coal company, paid nearly $1 million to a law firm that assisted two residents who opposed the project.

LEEDCo has 30 days to apply to the board for a rehearing, and can then appeal the decision to the Ohio Supreme Court if it chooses.

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Great Lakes offshore wind approval a 'poison pill' - alleghenyfront.org

Orsted has recruited two new executives to expand its US offshore wind team.

David Hardy has been appointed president and chief operating officer for Orsted North America Offshore, while Pamela Farrell Venzke joins as the units new president for external affairs.

Hardy, who joins Orsted from Senvion, will be based out of the Danish developers Boston and Providence joint headquarters.

Venzke, who joins from GE Power, will work out of Washington, DC.

Orsted North America Offshore chief executive Thomas Brostrom said: As we continue develop and expand our project portfolio in the US, Im thrilled to be welcoming such strong new voices to our leadership team.

David and Pamela bring unparalleled experience and expertise to our efforts as Orsted continues to lead the way in the North American offshore wind industry.

Hardy will oversee Orsteds end-to-end asset portfolio from development to operation.

At Senvion he served as executive director and chief sales officer overseeing all the regional activities of the company, including sales, construction, service and support.

Hardy said: The potential for offshore wind to transform our countrys energy landscape is real, and Orsteds experience, along with its push to develop new markets to grow this clean energy industry, is urgently needed.

Venzke will oversee teams managing government relations, public affairs, communications, sustainability and regulatory approvals.

At GE Power her role was managing director of global government affairs and policy and part of the units executive leadership team. She also served on the chairmans corporate law and policy council.

Its exciting to work in an emerging market that happens to be your home country, Venzke said.

The US is in a position to be a world leader in offshore wind and Orsted is the company that can get us there.

With more than 6.8GW in operation and another 3.1GW in construction, Orsted has the experience and the track record to establish offshore wind as a major power source and economic driver for the US at a time when we need that more than ever and I am so happy to be a part of this journey, she added.

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Orsted bolsters US offshore wind team - reNEWS

At Scotlands easternmost headland, the old fishing port of Peterhead juts out into the North Sea. On a clear day, says Alastair Reid, an economic development official with the Aberdeenshire Council, from the harbor you can just make out the turbines of the Hywind park.

In windswept northern Scotland, where abundant wind arrays both on land and off the coast vie for limited space, the distant location of the five towering 574-foot-tall turbines, 15 miles offshore, is just one novelty of this renewable energy project. Indeed, Hywind Scotland, which generates enough electricity for more than 20,000 homes, is the first wind energy array that floats on the seas surface rather than being dug into the ocean bed. Proponents say the technology heralds a new generation of green energy.

Whats groundbreaking about the Hywind project, located in more than 300 feet of water, is that the giant masts and turbines sit in buoyant concrete-and-steel keels that enable them to stand upright on the water, much like a fishing bobber. The turbines nearly 10,000-ton cylindrical bases are held in place with three taut mooring cables attached to anchors, which lie on the seafloor.

In contrast to ordinary offshore wind turbines, with long towers sunk into the seabed and bolted into place in shallow seas 60 to 160 feet deep, the advantage of floating turbines is that they can access large swaths of outlying ocean waters, up to half a mile deep, where the worlds strongest and most consistent winds blow. In Europe, where the density of onshore and near-shore wind turbines in places like Germany, the United Kingdom, and Norway has spurred increasing opposition to new arrays, the floating turbines can be installed over the horizon, out of sight of coastal residents.

Floating wind power has enormous potential to be a core technology for reaching the climate goals in Europe and around the world, says Frank Adam, an expert on wind energy technology at the University of Rostock in Germany.

The ocean space beyond the reach of conventional offshore turbines makes up 80 percent of the worlds maritime waters, opening the way for floating arrays, Adam says. In the past few years this technology has made great strides, and Hywind shows that it can work as a whole park, says Adam. Now the farms have to grow bigger to show governments and investors that theyre feasible on a really large scale.

Some renewable energy experts remain skeptical that the high costs of floating offshore wind turbines currently the electricity they generate is often almost twice as expensive as near-shore wind turbines and three times that of land-based wind turbines will come down far enough to rival other clean-energy technologies.

It will always be cheaper to build turbines on land, and that is where the [emissions-reduction] targets are going to have to be reached, says R. Andreas Kraemer, founder and director emeritus of the Ecologic Institute, a Berlin-based think tank. Even though the floating parks may be cheaper in some cases than fixed offshore wind power plants, and deployable over a larger sea area, it is still maritime engineering and that makes it expensive to build, deploy, and maintain. Lifespans of the stations are short because of the corrosive nature of the marine environment.

Floating wind turbines use chains to anchor to the sea floor up to a half a mile deep. Joshua Bauer/NREL

But advocates of floating wind arrays note that the costs of onshore and near-shore wind energy have been steadily falling as the efficiency of these technologies has been rising; the same trends, they contend, are likely to lower the costs of floating offshore wind. The Hywind Scotland array 75 percent owned by the Norwegian firm Equinor, formerly Statoil has been in operation for nearly three years and remained afloat and generating power during Hurricane Ophelia in 2017 and throughout other harsh winter storms with 100 mile-an-hour winds and 27-foot waves.

Other floating wind projects, some with turbines larger than Hywind, are now being built in Europe and Japan. In Portugal, the WindFloat Atlantic project, now under construction, is expected to produce enough power for 60,000 homes when it is completed later this year. France has floating wind power written into its clean energy plans and says it aims to be a world leader in deploying the technology. It has dedicated sites and price supports for wind farms off of Brittany and the Mediterranean coast. Scotland, which aspires to cover all of its electricity needs with renewables this year, has new floating parks in the works, including one just south of Hywind Scotland.

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Walt Musial, an offshore wind energy expert at the National Renewable Energy Laboratory, a research institute funded by the U.S. government, says that in the United States the coastal waters of both coasts are often too deep for conventional offshore wind turbines; nearly 60 percent of suitable offshore wind locations, he notes, exist in places at depths greater than 200 feet. That creates yet another opportunity for floating wind energy technologies.

Po Wen Cheng, head of an international research project on floating wind energy at the University of Stuttgart, says that floating turbines could produce more energy than the largest onshore or offshore technologies. Not only are winds in deeper waters more powerful than those closer to shore, he says, but the physics of the flexible, suspended rigs enables them to carry larger turbines. The bigger the turbine, the more energy they can produce in the right conditions, he says. Cheng argues that floating turbines could be even taller than todays largest offshore rigs, perhaps with 400-foot blades and towers stretching nearly 1,000 feet into the air as tall as the Eiffel Tower. Turbines of such dimensions could generate three times the electricity of todays most advanced onshore turbines, says Cheng.

Experts say that while some of the floating turbines finer mechanics are still being tweaked, the technology is sound. The oil and gas industry has used similar marine know-how for decades. (Hywind Scotlands chief owner, Equinor, is Norways largest oil and gas company.) And the masts and rotors are identical to those of conventional offshore wind turbines. Floating turbines can adopt a lot of knowledge and experience of the wind power development of the past 10 years, which gives them a huge jump, says Adam. Like conventional offshore wind arrays, the floating turbines transmit electricity to coastal grid connections through heavy-duty underwater cables.

In Europes ambitious plans to be carbon-neutral by 2050, wind energy of all types figures prominently. Although onshore wind parks are the most cost-effective solution, they have been met with stiff opposition from activists, who object to their marring the landscape, the proximity to their homes, and the impact on nature, particularly birds. In some countries, such as Germany and Norway, citizen opposition has nearly ground onshore wind to a halt.

Offshore wind farms in the North Sea, Baltic Sea, and elsewhere have substantially increased clean-energy production in Europe and driven down the price to a level competitive with fossil fuels. But Europes current offshore production is roughly 5 to 10 percent of the wind power supply that the International Energy Agency (IEA) and the European Union says Europe should reach by 2050 to meet its goals under the Paris Agreement. The problem is that a massive increase in near-shore wind arrays simply isnt feasible, in part because of growing opposition from fishing fleets, conservation groups, and coastal residents.

This is where floating parks enter the equation, says Jonathan Cole, the managing director of offshore wind energy at Iberdrola, one of the worlds leading producers of wind power. Green energy is going to be needed in all sectors of the economy, says Cole. Fixed-bottom offshore wind will be expanded far beyond what it is today, but it will run out of space, too, like onshore has in some places.

A floating turbine being pulled out to sea off the coast of Portugal for the WindFloat Atlantic project, now under construction. DOCKgo/WindFloat Atlantic

Ib Krag Petersen, a wildlife ecologist at Aarhus University in Denmark, says birds such as eagles, ducks, griffins, storks, and gannets can collide with the mammoth blades of offshore rigs. But deep-sea wind arrays, he says, where the density of the turbines and the communities of birds are more thinly distributed, have less of an impact on seabirds than near-shore wind arrays.

The Hywind project enjoys broad support in Aberdeenshire, Reid, the local economic development administrator, says. Among other things, Equinor has worked with the prominent fishing sector that docks at Peterhead so as not to interfere with its operations.

Investors and renewable energy companies say that the most formidable hurdle to full-scale rollout of floating wind arrays is recognition from governments, utilities, and financiers that the technology is viable and that costs will inevitably fall. We need commitments from governments, the way France, Scotland, and Japan have done, to help get bigger floating parks off the ground, says Bruno Geschier, chief sales and marketing officer of Ideol, a multinational offshore wind developer.

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Adam of Rostock University says, Its easy to produce one or half-dozen floating turbines, but 10 or 20 or 100, thats another story. This requires supply chains, shipyards, and ports that can handle such enormous structures, and factories for serial fabrication, he says.

Despite these challenges, the promise of harnessing so much of the open seas for renewable energy generation remains an enticing proposition. As the IEA has noted, in theory, offshore wind power alone could eventually meet the entire electricity needs of Europe, the U.S., and Japan many times over.

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Will Floating Turbines Usher in a New Wave of Offshore Wind? - Yale Environment 360