Daily Archives: June 1, 2020

Orions Heavy Lift Crane Collapses Video

A heavy-lift crane installed on the offshore installation vessel Orion has collapsed while undergoing load tests at the Liebherr construction yard in Rostock, Germany.

Siemens Gamesa Cranks It Up to 15 MW with Offshore Behemoth

Siemens Gamesa has launched a new SG 14-222 DD offshore Direct Drive wind turbine. The turbine model has a 14 MW capacity, reaching up to 15 MW using the companys Power Boost function, a 222m diameter rotor, 108m long blades, and a 39,000m2 swept area.

Worlds Largest Offshore Wind Farm Selects O&M Base

Equinor and SSE Renewables plan to build a new Operations and Maintenance (O&M) base at the Port of Tyne, UK, to service the 3.6 GW Dogger Bank offshore wind project.

Five Injured in Accident Onboard Seaway Strashnov

Five people were injured in an accident onboard the installation vessel Seaway Strashnov during the installation of foundations at the Triton Knoll offshore wind farm.

15 MW Siemens Gamesa Turbines for US Offshore Wind Farm

Siemens Gamesa Renewable Energy will conditionally supply SG 14-222 Direct Drive offshore wind turbines to the 2,640 MW Dominion Energy Coastal Virginia Offshore Wind (CVOW) commercial project.

Ireland Speeds Up Seven Offshore Wind Projects

The Irish government hasdesignated seven offshore wind projects as relevant, meaning they will be fast-tracked through the new marine planning regime.

First Jones Act Compliant Offshore Wind Installation Vessel Coming in 2023

A consortium led by Dominion Energy is developing a Jones Act compliant installation vessel for the U.S. offshore wind sector.

MHI Vestas Deck Carrier Ready to Serve Video

United Wind Logistics (UWL) has taken delivery of the deck carrier, MV BoldWind, which will shortly start her long-term charter with MHI Vestas Offshore Wind.

World Bank: 48 Countries Hold 15.6 TW of Offshore Wind Technical Potential

The World Bank has published maps and analysis of the offshore wind technical potential for 40 more emerging markets around the world, following itsreportfrom October 2019, when eight countries potential was estimated to be at 3.1 TW.

First Monopile Foundation Stands in US Federal WatersThe first monopile foundation has been installed at the Coastal Virginia Offshore Wind (CVOW) project, the first in U.S. federal waters.

Excerpt from:

Highlights of the Month - May 2020 - Offshore WIND

(Courtesy Bureau of Safety and Environmental Enforcement)

Offshore staff

WASHINGTON, D.C. Since its launch in May 2019, more than 6,200 subscribers have signed up for the BSEE!Safe text notification service.

The Bureau of Safety and Environmental Enforcement (BSEE) is the first regulator in the world to provide critical safety information directly to workers via text message.

BSEE Director Scott Angelle said: Offshore safety was the driver for this initiative. Steadily increasing subscriptions to the BSEE!Safe text messaging service demonstrates BSEEs leadership in pioneering ways to reach offshore workers.

The BSEE!Safe texts contain links to the bureaus published Safety Alerts and Bulletins which include safety recommendations resulting from incidents and near misses on offshore oil and gas facilities.

More than 120,000 text messages have been sent since its inception, according to BSEE.

BSEE!Safe is an efficient, timely way to communicate directly to the men and women who wear the hard hats and steel-toed boots; who kiss their families goodbye and set out to the OCS to do the hard work of fueling our nation, said Angelle.

Subscribers maintain their own contact information and can opt out of the service at any time.

In addition, the bureau has issued 41 Safety Alerts and Bulletins since the launch of the service.

06/01/2020

Here is the original post:

BSEE!Safe text notification service hits milestone - Offshore Oil and Gas Magazine

Newfoundlanders and Labradorians rely on industries such as our offshore oil and gas every day to keep the bills paid and food on the table.

Due to the ongoing pandemic for many, incomes have been cut drastically. I question whether the federal government has done enough to support cash-strapped Newfoundland and Labrador during these unprecedented times?

The short answer is no.

Canada needs to offer incentives for offshore exploration, right here off the coast of our province. The argument can be made that the price of oil is low and why develop more when the demand isnt there but look at it this way: the world needs oil and gas, Canada needs oil and gas.

We need to produce more of our own oil and gas, not rely on other countries such as Saudi Arabia.

Why? Because we use oil and gas every day to fuel our vehicles, it provides a source of electricity, its used as stove oil heat our homes the list just goes on and on.

Along with the direct use of oil and gas in our lives, this industry employs thousands, both directly and indirectly here in the province.

For example, our industry employs SAR techs, welders, mechanics, cooks, deckhand, sea captains, drillers. Onshore we see secretaries, HR staff and assistants employed at Noia or businesses like Cahill or Atlantic Towing, the list just goes on and on.

Businesses are going under, they are downsizing operations and pulling up stakes here in our province this just can't continue.

Our offshore oil and gas is the single greatest contributor to our economy, we need it to prosper and be explored to attain the best outcome. To achieve this outcome which would allow our province to return to surplus and balance our budgets, we need to renegotiate our Atlantic Accord along with having our elected officials in Ottawa putting Newfoundlanders and Labradorians best interests first, not Ottawa's.

Why not allow our offshore to be eligible for the Atlantic Investment Tax Credit? Its initiatives like these that will get boots on the ground and people back to work.

It has been done before, it can be done again; It is time for Newfoundlanders and Labradorians to finally get a hand up, not a handout.

Nathan RyanFerryland

RELATED:

Follow this link:

LETTER: Ignoring our offshore oil and gas industry will not get our province back on track - SaltWire Network

It didnt take long for the newly-unveiled biggest beast in the offshore wind jungle to make a big mark in the market.

Within a week of its launch, Siemens Gamesas 15MW machine was being lined up for deployment at the up-to 1.1GW Hai Long 2 project off Taiwan for developers Northland Power and Yushan Energy. The new 14MW giant is also in the frame for the 2.6GW Coastal Virginia project in the US, bringing the worlds biggest turbine to whats set to be Americas most ambitious offshore wind project to date.

The relentless scaling-up of offshore wind was central to another Recharge exclusive this week as we reported how Germanys Aerodyn is taking blades to a new level with a 111-metre design, a full three-metres longer than those on the new Siemens Gamesa SG14-222DD.

As the world recovers from a historic economic shock, green energy pacesetters like Vestas can lead the rebound and make sure the world is ready to face the next crisis climate change.

That was the message from the Danish wind giants CEO Henrik Andersen in an exclusive opinion column for Recharge this week setting out whats at stake as the EU and other policymakers lay their plans for economic stimulus packages.

Vestas itself was yet again confirmed as the wind sectors market leader by another industry study, while the OEMs global reach was underlined by its latest success in Vietnam.

The US wind market has reason to celebrate this week as the federal government confirmed projects will get more time under tax credit incentive programmes to take account of disruption caused by the Covid-19 pandemic.

Thats a relief to a industry that was facing big pressures on its supply chains and people although, as a Recharge analysis explained coping better than many sectors of the US economy.

US offshore wind wasnt part of the relief measures but marked its own milestone when construction work began at the first project in US federal waters, with first foundations now installed at Dominion Energy and Orsteds 12MW Coastal Virginia Offshore Wind pilot site.

On the downside, another US offshore wind plan the Icebreaker project on Lake Erie, Ohio declared itself stunned at a consent decision it claimed could make the long-percolating development unviable.

Read more from the original source:

Offshore rides the updraft, Vestas CEO's view and why US wind is coming up trumps - Recharge

By Kieran Hanley

The success of our offshore oil and gas industry is critical to Newfoundland and Labradors economy. We know this. But what may be surprising is that it is also a centrepiece of the provinces clean growth strategy.

Lets be clear: urgent action is required worldwide if we are to meet the objectives of the Paris agreement. But such fundamental changes in the economy, its infrastructure, and the habits of consumers that will be required will not happen overnight. Oil and gas represents upwards of 60% of global energy consumption. Demand for it doesnt just go away. Objectively, if the world has any hope of meeting greenhouse gas emissions targets, changes within the oil and gas industry have to be part of the solution.

This is the transition that we keep hearing about, and Canada can play a major role in helping to lead this shift. Its offshore industry puts us in an excellent position in this regard. We are lucky in that the type of oil in our offshore is the least impactful from an environmental perspective to process. And the GHG intensity of our operations are 30 per cent below the international average. This is to say that it is within our reach to set a global standard for the decarbonization of the industry. In this time of transition, reducing global emissions by providing the world with the most environmentally sound oil is a valuable contribution to the fight against climate change.

And there are substantial economic and clean growth prospects associated with that, with immediate opportunities for investment and improvement. An offshore wind farm Canadas first could lower our offshore assets.

Ditto for the abundance of clean energy we have flowing from Muskrat Falls. Either would achieve significant emissions reductions and represent major clean growth projects that would get people back to work and propel our industry into a new era of low-carbon operations.

Beyond such major projects, there are lots of things we can do to throughout the industrys vast supply chain. Zero-emissions supply vessels. Electrified ports. Major energy efficiency initiatives. Digitalized and remote operations. These activities represent clean, green economic growth. They are enormous cleantech research, development, and commercialization opportunities that can be exported worldwide and expanded through different ocean industries once commercialized.

We know this because we have already seen the pattern play out.

Because of the high environmental standards our offshore industry and its stakeholders have collectively put in place and adhered to, we have become a centre of excellence in the provision of products and services that help us characterize and monitor the environment. Our province is home to an unnaturally high number of SMEs with world class technologies using lasers, radar, sonar, and hi-def video in the skies and under the water that help us understand whats happening in the ocean. This expertise, which we export all over the world, would not have been developed without the offshore oil and gas industry. This past success is indicative of the opportunities before us if we embrace becoming the least carbon intensive oil producing region on the planet.

Further, you might have missed it but Newfoundland and Labrador has committed to achieving net zero carbon emissions by 2050. The offshore industrys support of this policy has the potential to dramatically alter the landscape of (and diversify) our economy. With new resources to finance a slew of new major emissions reduction projects, Newfoundland and Labrador could rapidly transition into one of the cleanest jurisdictions in the world with one of the most advanced clean growth economies.

But none of this will come to pass without immediate support for Canadas offshore oil and gas industry. A future without it would be very grim for Newfoundland and Labrador indeed, and would extinguish our best chance at becoming an international clean growth leader.

We are in the midst of an energy transition.

Canada has an opportunity to be a leader in that transition. The solutions we develop here can set the global standard, and our expertise and technologies can be exported worldwide for the betterment of the planet and our own economy.

This a worthy pursuit that we can all support.

Kieran Hanley is the executive director for the Newfoundland and Labrador Environmental Industry Association (NEIA). He writes from St. Johns.

RELATED:

Read more:

GUEST COLUMN: Canadas offshore oil and gas industry is the ticket to clean growth for Newfoundland and Labrador - The Telegram

You have access to this full article to experience the outstanding content available to SPE members and JPT subscribers.

To ensure continued access to JPT's content, please Sign In, JOIN SPE, or Subscribe to JPT

The complete paper discusses the systematic approach adopted by a service company to achieve the goal of safely abandoning wells offshore southwest Brazil with different completion types using light workover vessels. Having determined the abandonment methodology, service company personnel developed processes and procedures to reach the objective that included advances in coiled-tubing (CT) rigup procedures and use of a real-time telemetry system.

The use of a CT real-time telemetry system enables accurate setting of a through-tubing inflatable device system (T-TIDS) by monitoring the necessary downhole parameters in real time. The paper presents a case study wherein sensors [such as a casing collar locator (CCL) to perform depth correlation before setting the T-TIDS and placing cement plugs, a pressure sensor to monitor the T-TIDS setting, and a CT internal pressure sensor to help ensure all cement was pumped out of the CT] were used in real time to verify that well barriers were set in place, contributing to successful well abandonment. Real-time data collection proved to be the most-effective methodology for running critical equipment, thereby saving overall time and cost.

The decision for permanent abandonment of a well is not always easy. In Brazil, the National Agency of Petroleum, Natural Gas, and Biofuels (ANP) has established a compendium of rules for oil companies that extract and produce oil, gas, and derivatives. This involves a group of barriers known as CSB, which is a set of one or more elements with the objective of preventing the unintentional flow of fluids from the formation to the external environment and between intervals in the well considering all possible paths. The CSBs aim is to guarantee the isolation of intervals with current and future flow potential. Cement or other material with similar performance must be used as barrier elements.

Achieving a unique solution is dependent on having up-to-date information regarding the wellbore diagram, reservoir, history, well location, CT-performance capability, surface equipment, well-control equipment, and proposed layout. Fig. 1 illustrates the design of the 3D wellbore graph generated with modeling software.

The well discussed in this work contains deposits of asphaltene and sand-accumulation debris. For the operator to perform a plug-and-abandon (P&A) intervention, an effective solution to provide reliability safely is necessary to avoid worsening the well condition and delaying the intervention. The service company offered experienced personnel and engineering capabilities, a customized program for job-specific requirements, the CT package, and reliable processes and advantages compared with heavy workover units. Included as part of those advantages is a variety of bottomhole-assembly (BHA) tools that can be deployed in the well with the capability to be customized, working together with wireline operations and the robust management safety system.

T-TIDS are used in applications where the BHA must pass throughout a wellhead restriction or cased-hole restriction and must be installed at inner diameters larger than such restrictions. They can be used as remedial or completion applications. A T-TIDS was used to perform P&A applications in the operations discussed. T-TIDS applications include thefollowing:

Well-temperature variation before and after the T-TIDS installation influences the success of the operation. Once seated, temperature changes also will affect pressure inside the T-TIDS. Increased temperature can lead to overpressure until bursting, while decreased temperature can lead to falling or slipping of the T-TIDS. The pressure gradient is calculated during operational design according to the expansion of the T-TIDS pressure at which it will be installed and the well temperature before and after installation.

The design of service (DOS) is a requirement that helps ensure that the job purpose will be achieved. The DOS is prepared by an operational engineer on the basis of well data (wellbore diagram, reservoir, history, and well location) and an expected solution. The DOS presents topics related to customized intervention operations. Moreover, all BHA tools (including a contingency plan) necessary to perform the operation are included. In case of adjustable parameters during the operation, as per some variation of the well conditions or operator request, one update should be performed with all parties in agreement. The service company used modeling software to help the engineer customize job execution.

The BHA is the tool component conveyed by CT to reach the target and perform the operation. For this operation, it was used in addition to the basic tools such as a CT connector, a double flapper check valve, a disconnector, a rotary jetting tool, telemetry sensors, and the T-TIDS.

The use of a CT real-time telemetry system into the BHA enables accurate TTIDS setting through real-time monitoring of the necessary downhole parameters. The sensors used at the BHA in this well included internal/external pressure, temperature, tension-compression, and a CCL. The CCL was used to perform depth correlation before setting the T-TIDS and placing the cement plug with the real-time internal/external pressure signal to monitor T-TIDS setting and managing the CT internal pressure assist to help ensure that all cement was pumped out of the CT.

Before running the CT BHA with the TTIDS, a jetting and drift process was used to remove present incrustations inside the production tubing to help ensure successful T-TIDS setting. In this single run, three objectives are achieved in just one trip in/out:

The procedures followed for all eight runs are described in detail in the complete paper.

During this operation, three CSBs were installed in accordance with ANP regulations. The first CSB inside the 7-in. liner created a barrier between two formations, and two CSBs were constructed at a height of 129 m to act as the main well barriers. The annulus cement was pressure-tested with positive results per the operator report delivered to ANP. Additionally, the CSBs inside the production tubing also were pressure-tested and approved.

The BHA in the first and second run was slim because of the risk of CT becoming stuck in the subsurface safety valve. This approach represents one type of mitigation offered to the operator for customized operation. The slim BHA overcame issues during the operations, such as sticking of CT at a reference point, passing through a restriction, and providing the same assurance for the operation regarding tension/compression capacity.

The next six runs were aided using downhole sensors to determine the exact location of the BHA to position the rotary jetting tool and the cement retainer to meet national regulations. During the entire run, internal/external CT pressure was monitored in real time by a field engineer; in case of abnormal pressure noted while setting the T-TIDS, a contingency plan could be applied on time in conjunction with operator-enabled onsite decision making.

After eight intervention runs in the well using CT, the package was customized per operator request in real-time mode in the field during the operation. The reliable execution process showed operability to P&A per regulations with adherence to all health, safety, and environment policies, one of the more important execution aspects within the industry. The success of this kind of dynamic intervention is the result of careful planning (DOS and simulation), daily BHA-tool maintenance, continuous monitoring of well conditions, and an excellent partnership with the operator in both the field and the office.

Overall, the results obtained with this intervention show that operational time was reduced because of efficient execution of the equipment and process, such as the real-time data-acquisition system, the depth-correlation (CCL) sensor, real-time interpretation of signals during the operation, and efficient T-TIDS setting procedures.

Originally posted here:

Coiled Tubing Sets Packers Precisely During Offshore Well Abandonment - Journal of Petroleum Technology

You have access to this full article to experience the outstanding content available to SPE members and JPT subscribers.

To ensure continued access to JPT's content, please Sign In, JOIN SPE, or Subscribe to JPT

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.

Go here to read the rest:

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.

Here is the original post:

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

Read more from the original source:

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.

Read this article:

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