ALERT: Update ITC/Deer Park Shelter-in-Place

What is the danger?

Our first concern is for the safety of our community. We have identified benzene vapor coming from the site of the fire. We knew vapor releases were a possibility and our plan was activated and executed as designed.

Harris County pollution control and the Texas National Guard’s 6th civil support team, Harris county hazardous materials team and City of Houston’s hazardous materials team have set two perimeters at varying distances around the site to identify and analyze air quality readings in real time.

The readings have crossed our very conservative air quality standards, related to OSHA standards, to determine, out of an abundance of caution, there should be a shelter in place in the immediate area, which the city of Deer Park has announced.

We know this is concerning, especially to residents in the area of the shelter in place. We are continuing to monitor to verify if this is a short-term, one-time exposure or a longer exposure. At the level of Benzene, we are seeing now for the current duration it should not cause symptoms even in the area impacted. That said, if you believe you are having symptoms and are sheltered in place, please call 911.

As a precaution, several schools have canceled classes for today.

School Closures

Deer Park ISD
Channelview ISD
Galena Park ISD
La Porte ISD
Sheldon ISD
KIPP Intrepid
San Jacinto College

Road Closures

SH 225 from Beltway 8 to Hwy 146

 

What you should do:

 

Residents are advised to remain indoors and to close all doors, windows and other sources of outside air. Turn off air conditioning or heating systems and close the fireplace damper to keep chemical vapors from entering.

Please continue to monitor the City of Deer Park outlets for updated information.

Full Shelter-in-Place instructions

Per Deer Park’s website, http://www.deerparktx.gov/1722/Shelter-In-Place, instructions for Shelter-in-Place are as follows:

  1. Go Inside Immediately: Seek the nearest enclosed structure, whether it is a house, business, garage or vehicle. If you know of any unattended child in your neighborhood, call them and tell them to remain indoors. Keep any pets inside also. Gather emergency supplies like a portable radio, flashlight and extra batteries.

  2. Close all doors, windows and other sources of outside air. Turn off air conditioning or heating systems and close the fireplace damper to keep chemical vapors from entering. Ceiling fans or rotary fans inside the building can be safely used to keep cool.

Cover any gaps, holes or cracks with wet towels or sheets to prevent vapors from entering your home.

If you have trouble breathing, contact 9-1-1.

Our community’s health and safety is our primary concern. The vast majority of our community is seeing no elevated readings.

We have increased monitoring in the area and will keep our community informed.

For real-time information on readings and public health visit readyharris.org/deerparkfire

Where you can learn more:

  • Air Quality Data: ReadyHarris.org

  • Health Information: Harris County Public Health

  • Fixed Air Monitoring Sites: TCEQ

Follow ReadyHarris on TwitterFacebookInstagram and YouTube | Download the ReadyHarris A

Recommended Lighting Practices Collaboration

FORT DAVIS, Texas — The University of Texas at Austin’s McDonald Observatory has collaborated with the Permian Basin Petroleum Association (PBPA) and the Texas Oil and Gas Association (TXOGA) to reduce light shining into the sky from drilling rigs and related activities in West Texas. The excess light has the potential to drown out the light from stars and galaxies and threatens to reduce the effectiveness of the observatory’s research telescopes to study the mysteries of the universe.

“This partnership of PBPA and TXOGA with McDonald Observatory to protect dark skies in its vicinity is vital to the research of the universe taking place at McDonald,” said Taft Armandroff, director of the observatory.

The collaboration’s Recommended Lighting Practices document details best lighting practices for drilling rigs and other oilfield structures, including what types of lighting work best and how to reduce glare and improve visibility. These practices will increase the amount of light shining down on worksites, thus increasing safety while decreasing the amount of light pollution in the sky. Reducing excess light helps the observatory and also decreases electricity costs for the oil and gas producers.

The document specifically targets oil and gas operations in the seven counties with existing outdoor lighting ordinances surrounding the McDonald Observatory: Brewster, Culberson, Hudspeth, Jeff Davis, Pecos, Presidio and Reeves. However, the recommendations can be beneficial across the industry.

A new video that helps to introduce the recommendations to oil and gas companies is now available. It features the observatory’s Bill Wren explaining the importance of dark skies, and how lighting practices can both preserve dark skies and improve safety for oilfield workers. The video was produced with the support of the Apache Corporation, following the company’s extensive collaboration with observatory staff and implementation of these practices with their assets in the area. It is available to watch and share at: https://youtu.be/UnmwnO6CIR4

“For years, the PBPA and the McDonald Observatory have worked together on educating members of the Permian Basin oil and gas community about the Dark Skies Initiative and the possible impact lighting practices can have on the observatory’s work,” said PBPA President Ben Shepperd. “About two years ago, the PBPA board of directors agreed to support the creation of lighting recommendations. We decided a great way to educate members of the industry on how they could provide a positive impact on this issue was through the utilization of such recommended practices.

“So we began work with the observatory to publish recommended lighting practices and have since worked to educate our members and those outside the oil and gas industry on the recommendations through presentations, seminars, articles in magazines and newspapers, and even one-on-one conversations,” Shepperd said.

Recently, the Texas Oil and Gas Association joined the collaboration.

“The Texas Oil and Gas Association recognizes that production practices and protecting the environment are in no way mutually exclusive,” TXOGA President Todd Staples said. “The Recommended Lighting Practices collaborative effort allows for the oil and natural gas industry to continue the work vital to our economy and our future, and for the simultaneous reduction to our ecological footprint.”

In April, the observatory’s Dark Skies Initiative was named one of six Texan by Nature Conservation Wrangler projects for 2018. Texan by Nature, a Texas-led conservation nonprofit founded by former first lady Laura Bush, brings business and conservation together through select programs that engage Texans in the stewardship of land and communities.

The award will provide the observatory connections to technical expertise, industry support, publicity, and more for its Dark Skies Initiative.

“Our Conservation Wrangler program recognizes innovative and transformative conservation projects across the state of Texas,” said Joni Carswell, the organization’s executive director. “Each Conservation Wrangler project positively impacts people, prosperity and natural resources.”

— END —

Media Contacts:
Rebecca Johnson, Communications Manager
McDonald Observatory
The University of Texas at Austin
512-475-6763

Stephen Robertson, Executive VP
Permian Basin Petroleum Association
432-684-6345

Kate Zaykowski, Communications Director
Texas Oil and Gas Association
325-660-2274

Taylor Keys, Program Manager
Texan by Nature
512-284-7482

Castlen Kennedy, VP of Public Affairs
Apache Corporation
713-296-7189

Case Study: Large E&P Operator in Permian Basin Uses ZerO2 to Reduce Emissions, Capture Full Value of Production Stream

Situation

A multinational exploration and production company with significant operations in the Permian Basin needed a solution to continue developing its oil and gas assets in compliance with stringent emissions standards and without increasing lease operating costs or reducing economic returns. The operator’s area of operation covers over 100,000 net acres reaching from the city of Midland in west Texas to the border of New Mexico. The company recently told the market it plans to invest heavily in the Permian Basin by 2020 to grow production significantly. To achieve its growth plan, the operator required a solution to proactively handle emissions of Volatile Organic Compounds (VOCs) from tank vapor gas and Nitrogen Oxides (NOx) produced when VOCs are burned using flares or combustors. Importantly, the solution needed to have a minimal impact on operating costs and not require significant capital investment.

Solution

The operator turned to EcoVapor for a solution to handle its emissions of VOCs and reduce or eliminate NOx while avoiding any adverse impact to operations, cash flow or financial returns. EcoVapor applied its ZerO2 oxygen removal technology in a staged rollout covering an initial five production pads. Born from EcoVapor’s proprietary vapor recovery technology, its patented ZerO2 systems offer operational flexibility, modularity, and reliability. ZerO2 units can be all-electric, using existing lease power or gensets, are skid mounted and have a small 4’x4’ footprint so they can be installed on any production pad. With no moving parts, ZerO2 units are extremely reliable.

The ZerO2 rollout proceeded as follows:

  • September 2017. Three ZerO2 units installed and run in parallel on the first production pad, handling over 1.0 MMcf per day of flash gas.

  • October 2017. Three more ZerO2 units installed on second production pad handling 800 Mcf per day of flash gas.

  • December 2017. Three additional ZerO2 units installed on third production pad handling an initial 750 Mcf per day. Additional development drilling and turning more wells to production increased production and in April 2018, two more ZerO2 units were installed to process flash gas volumes of up to 1.5 MMcf per day.

  • July 2018. Six ZerO2 units were installed on a fourth production pad with the capacity to process an expected 1.8 MMcf per day of flash gas.

 

Results

The ZerO2 solution gave the operator a scalable, efficient and reliable method to process rising flash gas volumes generated from the continued development of its Permian Basin asset position.

The multiple operational, economic and regulatory benefits of implementing the ZerO2 solution are summarized below:• Eliminate the flaring or combusting of flash gas by capturing 100% of tank vapors, as compared to typical efficiency levels of 80% for competing solutions.

  • Easily achieve compliance with current emissions standards and even more stringent regulations likely to be introduced by federal and state regulators in the future.

  •  Reduce Reid Vapor Pressure (RVP) by flashing gas at atmospheric pressure and capturing it before the oil is transported.

  • Generate incremental revenue and profits by capturing and selling rich, high-value tank vapor gas previously lost by flaring or combusting.

  • Improve the quality of sales gas by removing oxygen from the gas stream and ensuring consistent, ongoing production and revenue by avoiding the triggering of slam valve safeguards.

  • Maintain operational reliability by adopting the ZerO2 units, which have no moving parts and minimizes the impact on unexpected maintenance and repair costs.

This table summarizes the estimated emissions reductions based on installations made to date. Emissions reductions are estimated based on an 80% efficiency rate generally attributed to Vapor Recovery Tower technology. To put the impact of the total estimated emissions reductions in perspective, the reduction in VOC emissions is equivalent to
removing approximately over 28,000 passenger vehicles from the nation’s roads for a year, using per-vehicle estimates from the EPA’s publication Average Annual Emissions and Fuel Consumption for Gasoline-Fueled Passenger Cars and Light Trucks.

Based on the successful applications of the ZerO2 solution, the operator requested that EcoVapor design a larger unit to handle greater volumes of flash gas expected to be produced by its Permian Basin growth plan. These new units can each process 1.2 MMcfd and will be deployed in the second half of 2018.

Contact us today at 1.844.NOFLARE (844.663.5273) or [email protected] to see if ZerO2 is right for your operations and if you’re ready to Flare Less, Sell More.

Case Study Permian Basin

 

Schlumberger’s Stewardship Tool

Schlumberger Global Stewardship

A long-standing culture of social and environmental stewardship worldwide

The Schlumberger Global Stewardship journey is continuing to gain momentum as the company works with customers, investors, NGOs and other relevant organizations to achieve its environmental, social, and governance (ESG) objectives.

The most recent Schlumberger Global Stewardship Report outlines the company’s approach to ESG that is rooted in a long-standing culture of social and environmental stewardship worldwide. As a business and a community of individuals, Schlumberger focuses on areas where its organizational strengths, technological expertise, and cultural values can have the greatest impact.

The report describes Schlumberger Global Stewardship initiatives such as:

Technological expertise

The company has developed software technology that incorporates sustainability into its engineering and operational practices by modeling efficiency gains at the wellsite that yield a lower environmental footprint. By modeling its environmental footprint relative to metrics such as emissions, air quality, water use, noise, and chemical exposure, the unique web-based software is used to evaluate potential projects related to well stimulation. This software, known as the Stewardship Tool, has played an important role in the development of many next-generation technologies, such as the BroadBand unconventional reservoir completion services and the Automated Stimulation Delivery Platform.

Sustainable development

In 2017, Schlumberger became the first associate member of IPECA, the global oil and gas industry association for environmental and social issues. Schlumberger participated in IPIECA’s development of Mapping the Oil and Gas Industry to the Sustainable Development Goals: an Atlas, a publication describing the implications of the United Nations Sustainable Development Goals (SDGs) for the oil and gas industry and how IPIECA members may provide support in achieving these goals.

Community outreach

Schlumberger has a long-standing commitment to science and engineering as well as health and safety. This forms the basis of the company’s community outreach initiatives which includes programs that support science, technology, engineering and mathematics (STEM) education as well as health, safety and environment (HSE) workshops for youth—both local and global—many of which are supported by employee volunteers.

To learn more about these and other best practices, download the latest edition of the Schlumberger Global Stewardship report here.

Published Date: 09/14/2018

Source: www.slb.com

 

Colorado Cleantech Industries Association Announces Winners of the 2018 Oil & Gas Cleantech Challenge

Sep. 11, 2018 / PRZen / GOLDEN, Colo. — The Colorado Cleantech Industries Association (CCIA) announced Modern Wellbore Solutions, Avivid Water Technology, Cold Bore Technology, and Direct-C the top presenters of the 2018 Oil & Gas Cleantech Challenge (OGCC) and Modern Wellbore Solutions as the winner of the $5,000 grand prize.

Managed in partnership with BP Lower 48, Noble Energy and ConocoPhillips, the OGCC assists the extractive energy industry in identifying new technologies to make energy development safer, cleaner and more environmentally responsible. Following an international call for applications, the partners selected 10 companies, five from the U.S. and five from Canada to present to investors and decision-makers from the oil and natural gas ecosystem.

The top four presenters of CCIA’s 2018 Oil & Gas Cleantech Challenge were:

Modern Wellbore Solutions – Winner of the $5,000 grand prize, Modern’s stackable, full-bore, fracture treatment pressure rated Multilateral Junction Tool allows access to multiple reservoirs or pay zones from one motherboard, gaining more production while lowering costs during an interventionless completion.

Avivid Water Technology – Avivid is dedicated to enhancing the world’s water resources, using advanced technologies, that reduce or eliminate the need for chemicals to purify water.

Cold Bore Technology – Cold Bore’s SmartPAD is the world’s first ECR (Electronic Completions Recorder) which is providing completion operations of the future, today.

Direct-C – Direct-C provides certainty and reliability in 24/7 leak detection monitoring for liquid hydrocarbons &/or produced water, completely free of false positives; when an alert is received, immediate actions can be taken to mitigate the leak and its impact.

“Industry executives and sponsors were extremely impressed with the presentations and how well the teams addressed the challenges posed,” said Shelly Curtiss, CCIA’s executive director. “Each year the technologies are further along in development and deployment and it becomes harder and harder to select a winner. We truly appreciate the partnerships that make this program possible and we look forward to planning a robust 2019 Challenge.”

Companies applying for the OGCC were asked to provide novel technologies capable of working on issues related to unmanned aerial vehicles, digital oilfield, items to reduce truck traffic, blockchain, space-saving items to reduce footprint, plant or biological solutions, air, water, remote/distributed power, power management, advanced materials and chemicals. Companies selected to present on September 6 included

  • Aimsio

  • Avivid Water Technology, LLC

  • Cold Bore Technology

  • Direct-C

  • LongPath Technologies, Inc.

  • Modern Wellbore Solutions, Ltc.

  • Osprey Informatics

  • Raven SR

  • Transworld

  • Vesmir Inc. (PetroDE)

In addition to industry partners, the 2018 OGCC was supported by Wells Fargo Foundation, Consulate General of Canada in Denver, Colorado Energy Office, Altira, Perkins Coie, Rocky Mountain Institute, and Metro Denver Economic Development Corporation. For more information about the OGCC, please visit www.coloradocleantech.com/oilgaschallenge/

About CCIA

Founded in 2008, Colorado Cleantech Industries Association (CCIA) is a statewide organization dedicated to promoting Colorado’s cleantech industries. CCIA impacts Colorado’s policies, people, products and programs that drive the expansion of a cleaner, cheaper, more efficient and secure energy economy. Through advocacy, public policy leadership, development, and education, CCIA works to ensure that Colorado is a global cleantech leader. For more information about CCIA, visit www.coloradocleantech.com.

Follow the full story here: https://przen.com/pr/33270069

PRESS RELEASE: The IoT Solutions Awards acknowledge the year’s best innovations for the industrial internet

IoTSWC 2018 awards Huawei, IoTerop-Synox, Nokia and Intel-ARM-Pelion for their innovative solutions

Huawei, IoTerop-Synox, and Nokia were this year’s winning companies at the IoT Awards held at IoT Solutions World Congress, the leading international industrial internet event organized by Fira de Barcelona in recognition of the best projects developed in the field of the industrial internet throughout the last year. Similarly, the solution jointly developed by Intel, ARM, and Pelion enabling users to connect any IoT device to the cloud in a matter of seconds received the award for the best testbed at the show, which is being held for the fourth time until tomorrow at Fira de Barcelona’s Gran Via venue.

In the Business Transformation category, the award went to the Huawei OceanConnect IoV (Internet of Vehicles) platform applied by the Groupe PSA car firm. This platform makes vehicles smart by transmitting data to the cloud securely, reliably and efficiently, transforms the service provided by car manufacturers and contributes to the development of smart transport.

The Industry Award went to the system for non-intrusive industrial monitoring at nuclear plants, based on smart cameras built by the IoTerop and Synox companies for Électricité de France EDF, the leading electricity generation and distribution company in France. This IoT solution is capable of managing assets and optimizing the existing equipment and maintenance tasks at the EDF Golfech nuclear plant in real time.

Nokia’s “Sensing as a Service” project won the award in the Innovative Technology category. This is a platform developed for Cellcom, a regional wireless service provider in the USA, which collects and processes data from sensors in real time and sells it in a marketplace managed on the blockchain platform. The information collected includes environmental data and data for predicting anomalies in the industrial environment, controlling hardware and monitoring production plants.

The IoT Awards also presented an award to the best of the 10 testbeds exhibited this year at IoT Solutions World Congress. The jury decided that the winner was the solution developed by Intel, ARM, and Pelion for Hitachi and Infosim, enabling its operators to plug in, connect and use any device on IoT platforms in a matter of seconds. This prototype is highly innovative, as it currently takes between 20 and 40 minutes to configure an IoT device and provision it in a cloud management system and, in most cases, prior configuration by the manufacturer or manual configuration by a qualified installer is required.

Among the finalist companies of this year’s IoT Awards were Serimag, Libelium, Tellmeplus, Witrac, Neuron Soundware, Huawei Technology, Dassault Systèmes, and Nymea.

The IoT Solutions Awards Gala was held in the Italian Pavilion at the Montjuïc venue and brought together the main actors in the international industrial internet field.

Barcelona, October 2018

Oil And Gas CEO: New Tech Creates Opportunity

Data from KPMG’s 2018 Oil and Gas CEO Outlook, released Oct. 10, reveals that globally, almost all oil and gas CEOs believe new technology creates opportunities. Eighty-five percent are piloting or have already implemented Artificial Intelligence (AI).

However, only 59 percent feel their organization is an active disruptor in their own sector, and 57 percent feel that the lead times to achieve significant progress on transformation can be overwhelming

“Technology is disrupting the status quo in the oil and gas industry. AI and robotic solutions can help us create models that will predict behavior or outcomes more accurately, like improving rig safety, dispatching crews faster, and identifying systems failures even before they arise. This level of predictability can have a profound impact on our industry, said Regina Mayor, Global Sector Head, Energy, and Natural Resources, KPMG.

When asked about the biggest long-term benefits of AI, 46 percent of CEOs indicate an acceleration of revenue growth, 39 percent indicate increased agility as an organization, and 39 percent point to improved risk management, all within a three-year time frame. Further, they indicate high levels of confidence in their organizations’ digital transformation programs, AI systems, and robotic process automation.

Further, 58 percent of O&G CEOs feel AI and robotics technologies will create more jobs than they eliminate. In fact, 93 percent of CEOs expect an increase in industry-wide headcount over the next three years.

As oil prices remain elevated, industry confidence is up and CEOs are setting their sights on growth opportunities, with 85 percent very confident or confident on industry growth, and 88 percent very confident or confident on company growth prospects.

As part of their growth strategies, 83 percent of O&G CEOs anticipate a moderate to a high appetite for M&A activity over the next three years, largely driven by the need to reduce costs through synergies/economies of scale; a speedy transformation of business models; increased market share and low-interest rates.

“The higher price of oil is playing a significant role in driving a more positive sentiment across the industry,” said Mayor. “Executives are really honing in on ways they can improve internal efficiencies through strategic M&A moves and the use of robotics, AI and other means of digitalization across the industry.”

Despite a rosy outlook, there are still concerns and threats to achieving growth. Among the biggest threats to, 23 percent of CEOs point to emerging/disruptive technology risk, 20 percent say environmental and climate change risks and 18 percent point to a return to territorialism are most concerning.

Publisher by: Laxman PaiWednesday, 10 October 2018 23:36

SOURCE: OFFSHORE ENGINEER

Video

Drill cuttings and oil waste plant installed directly at the oilfield

TDP-2 pyrolysis plant designed for drilling waste treatment was installed at oilfield of oil and gas company. The plant is capable to obtain the valuable products from oil sludge thus there is no need in waste depositing. More details: http://tdplant.com/ Музыка: No Copyright Free Music GENERIC MUSIC https://youtu.be/X-ZwX5lyyy4?list=PLI…

Published on Feb 7, 2017

YouTube

To make sustainability real, make it personal

Neil Hawkins and Joe Árvai

Marc-Grégor Campredon 

Dow employees applying real-time learnings from the Sustainability Academy to their team project, designed to support one of Dow’s 2025 Sustainability Goals.

From the perspective of business, engaging employees is critical to developing and advancing a company’s sustainability goals. The feeling is mutual from the perspective of current, not to mention future employees: A company’s sustainability goals are important to the process of attracting and retaining the top talent.

But meaningful engagement across the entire spectrum of a company’s operations can be challenging. Many employees are often unsure how their job roles connect with a company’s sustainability programs and strategies, and many companies find it challenging to integrate — and inspire — leadership on sustainability in the day-to-day activities in their workforce. The net result: Employees often end up being an underused and undermotivated resource in a company’s sustainability journey.

Dow recognized these challenges early on and began to address them with its company-wide commitment to 2015, and now, 2025 Sustainability Goals, which have sought to redefine the role that business plays in society. A primary objective of the goals is to mobilize the human element — employees, suppliers, customers and the communities in which they live and work — to improve the well-being of people the world over.

To take the 2025 goals to the next level within the company, Dow collaborated with the Erb Institute of the University of Michigan in 2017 to design and launch the Dow Sustainability Academy. The Dow-Erb partnership has proven to be incredibly successful, productive, fun and, yes, sustainable. Dow brought to the table its decades of experience on making business sustainability real, and Erb brought its 20-year track record of being at the leading edge of research and teaching at the intersection of business, society and the environment.

The result of this partnership is a business-sustainability leadership and development program that provides Dow employees with the tools and insights they need to bring sustainability into their daily work. As part of the academy, Dow employees — selected as part of a competitive, application-based process — spend a week in training at the Erb Institute.

During this time, they learn from and interact with some of the world’s leading experts on a wide range of topics, from making the business case for sustainability and the policy backdrop against which business sustainability unfolds, to hands-on tools for implementing the elusive triple bottom line. When the in-class sessions come to a close, academy participants work on real-world projects related to one of the Dow sustainability goals and are given six months to use what they learned in Ann Arbor to complete them.

Recently, we had the pleasure of watching project teams from the second group of academy members present their project solutions to Dow leaders, as well as to the next contingent of employees chosen to be part of the academy. Each team passed along their advice to their successors in the academy, and it struck us while we listed to them that their learnings apply to not only academy participants but to anyone seeking to collaborate, stretch and grow at their company and in their career.

Here’s some of what we heard:

Avoid solutions that are attractive only because they are obvious or easy. One team was asked to determine the theoretical limits of how much emissions can be reduced from each Dow site, plant, equipment and technology. The aim was to help Dow achieve its 2025 Operations Sustainability Goal of growing the company globally over the next decade without allowing the company’s greenhouse gas emissions to exceed its 2006 baseline.

Team members had to reach outside their area of expertise and talk with dozens of people across Dow sites to understand and catalog the possible opportunities. By asking questions and — importantly — challenging assumptions about what previously were thought to be the performance range of various technologies and equipment, the group was able to identify additional, significant opportunities for reducing emissions.

When you face challenges, remember that your vision and passion are your North Star. All the projects carried out by academy participants require engaging in complex systems and with multiple stakeholders. In this kind of environment, sustainability objectives aren’t easy to define, and decisions must be made in an information-rich environment characterized by high levels of uncertainty.

One team, tasked with reducing food waste at a Dow site as part of the company’s goal to advance a circular economy, admitted that it was easy to get lost in rabbit holes or mired in red tape. However, by being true to their vision of what was possible, and by being persistent — “no” was not an acceptable answer — they were able to find both a workable solution for composting at a Dow site and identify local groups receptive and able to receive the compost.

Make “change agent” part of your job description. There’s a saying at Erb: When it comes to sustainability in business, be prepared to invent the job you want and then go do it. In other words, don’t wait to be anointed; being a change agent is a title you can bestow upon yourself.

The same goes for participants in the academy. One group was tasked with identifying a single project that aligned neatly with Dow’s valuing nature goal; the requirements were that the project had to be good for business but even better for the natural environment. Rather than identifying just one project, members took it upon themselves to identify one project each, for a total of three. From creating sustainable prairie habitat at company headquarter and planting native grasses to reduce erosion at a Seadrift, Texas, site to waste reduction at a plant in Freeport, Texas, these projects were heralded for their ability to cut emissions, rehabilitate the environment and bring business value to Dow.

As we get set to embark upon our fourth Dow Sustainability Academy, we could not be more delighted by what we have seen from those who have graduated from it. By thinking critically and creatively about sustainability’s role on the job, employees not only found answers to drive Dow’s sustainable practices but established critical leadership skills.

They learned to apply ingenuity and entrepreneurial spirit to address sustainability challenges and to respond to sustainability opportunities.

They began to see those sustainability decisions are real opportunities for setting and then achieving objectives and that business sustainability really is a journey that will require vision, leadership and course corrections along the way.

And they found that no matter their job titles, they actively could incorporate tools for sustainability into their jobs — and into their lives outside of work — in order to be champions for lasting, positive change.

That’s a win for employees, for Dow and Erb, and — most importantly — for society

 

Source: GreenBiz

Siemens and Southern Idaho Solid Waste announce commissioning of landfill gas-to-energy project

Siemens and Southern Idaho Solid Waste announce the commissioning of landfill gas-to-energy project

  • Siemens gas engines generating electrical power from landfill gas to provide energy for approximately 2,000 homes in Idaho

  • Two engines convert 1,000 tons of landfill waste daily into energy

  • The project marks successful use of Siemens’ highly-energy-efficient engines to capture and use methane

Siemens and Southern Idaho Solid Waste (SISW) recently announced the successful commissioning of two SGE-56HM gas engines that are providing environmentally friendly electrical power for a landfill gas-to-energy project at the Milner Butte Landfill in Burley, Idaho. Siemens’ gas capture engines are helping to convert 1,000 tons of landfill waste daily into energy but SISW officials expect that amount to increase in the near future.

Decomposing waste gives off massive amounts of greenhouse gases, especially methane. SISW engineers worked with Siemens and Siemens’ channel partner, Industrial-Irrigation Services, to develop a solution that would capture the methane for use as a fuel gas to produce electricity. “We saw this gas and realized we were just wasting it by burning it for no productive use,” said SISW’s environmental manager, Nate Francisco.

To capture methane and convert it into electricity, the Milner Butte Landfill deployed two Siemens SGE-56HM gas generator sets to run on the waste gas from the landfill and generate electrical power. Once the landfill gas is converted to electricity, it is transported to Idaho Power through a 20-year purchase agreement and is used by the community as a low-cost source of power. To date, the two engines have been generating enough power for approximately 2,000 homes. Each set is rated at
1,300kWe and includes generator controls and a power panel.

Siemens SGE-HM series is purpose-built for landfill gas-to-energy power applications. By incorporating advanced technology and design into the cylinder heads, valves, camshafts, and turbochargers, the SGE-56HM engine provides customers like SISW with a high-performing low-operating-cost solution.

“We expect these engines to remain in operation for 20 to 30 years,” said Josh Bartlome, executive director at SISW. “They’re big engines built for endurance.”

SISW estimates that within the next 20 years the facility will generate approximately $36 million in revenue, netting about a third of that after costs and inflation. Creating a long-term revenue generator like this model used by SISW will allow the District to realize lower power costs.

“The Milner Butte Landfill project represents the future of distributed power,” said Chris Nagle, North American Regional Director for Siemens Gas Engines business. “This plant assists the local community with its power needs while being environmentally responsible. Siemens is proud to support SISW and Industrial-Irrigation Services with this project.”

This press release and press pictures are available at www.siemens.com/press/PR2018100009PGEN

For further information on Siemens Gas Engines, please see: https://sie.ag/2MOzVRJ

Contact for journalists
Janet Ofano
Phone: +1 803-389-6753; E-mail: [email protected]

IoT Solutions World Congress will focus on the role of Women with the Women Leadership in IoT panel

The leading IoT event aims to contribute to reducing the gender gap within the technology industry

When the gender gap in the technology industry is analyzed, everyone admits that there is a significant difference in the number of women working in this sector if compared to men, with some studies concluding that only one out of every five tech workers is a woman. Reversing this situation is one of the challenges that the IoT Solutions World Congress, the leading event on the industrial applications of the Internet of Things (IoT) is addressing with the Women Leadership in IoT panel.

The conference will feature six inspirational women leaders in industrial IoT representing established corporations and startups: Leila Dillon, VP of Global Marketing; NA Distribution at Big Belly; Helena Lisachuk, member of the IoT Global Initiative; Beverly Rider, SVP; Chief Commercial officer and Hitachi; Eva Schönleitner, Group Vice President of Digital partnerships at ABB; and Adriana Estevez, Executive
Director for Digital Transformation and Innovation at Microsoft.

The director of IoT Solutions World Congress, Roger Bou has stressed that “for us, as the top international event within the IoT industry it is paramount to promote initiatives not only to help the sector grow but also to make it better. We strongly believe that helping women to have more presence and more important roles will also help the industry thrive.” “With this Women Leadership in IoT initiative, we also aim to create a
networking space for women in the sector to meet, discuss new ways to reduce the gender gap and network to create new opportunities for them and other women in this field”, added Bou.

Following the panel, a cocktail will be provided giving you the opportunity to connect with the panelists and other women in various aspects and careers in Industrial IoT.

The international IoT benchmark event

IoTSWC is the leading event on the industrial internet and the digital transformation of business sectors, combining a congress, a commercial exhibition, and test benches. Its next edition expects to gather together 300 exhibitors and 250 speakers from around the world. This year’s show is set to showcase the growth of the IoT and its widescale implementation across a range of industrial and business applications and will
also demonstrate the convergence of this technology with artificial intelligence and blockchain. More than 13,000 professionals from 114 countries visited the IoTSWC 2017.

IOTSWC is a part of the Barcelona Industry Week, a platform organized by Fira de Barcelona to promote the so-called Industry 4.0 and its application in all sectors. In 2018 it comprises three events, Healthio, In(3D)ustry From Needs to Solutions and IoT Solutions World Congress (IoTSWC).

Barcelona, 25th of September 2018

Subsurface Data in the Oil and Gas Industry

Probing beneath the Earth’s surface for exploration and hazard mitigation

Drilling for oil and gas is expensive. A single well generally costs $5-8 million onshore and $100-200 million or more in deep water.1 To maximize the chances of drilling a productive well, oil and gas companies collect and study large amounts of information about the Earth’s subsurface both before and during drilling. Data are collected at a variety of scales, from regional (tens to hundreds of miles) to microscopic (such as tiny grains and cracks in the rocks being drilled). This information, much of which will have been acquired in earlier exploration efforts and preserved in public or private repositories, helps companies to find and produce more oil and gas and avoid drilling unproductive wells, but can also help to identify potential hazards such as earthquake-prone zones or areas of potential land subsidence and sinkhole formation.

Mapping the Subsurface 1: Regional Data from Geophysics

In the 21st century, much is already known about the distribution of rocks on Earth. When looking for new resources, oil and gas producers will use existing maps and subsurface data to identify an area for more detailed exploration. A number of geophysical techniques are then used to obtain more information about what lies beneath the surface. These methods include measurements of variations in the Earth’s gravity and magnetic field, but the most common technique is seismic imaging.

Seismic images are like an ultrasound for the Earth and provide detailed regional information about the structure of the subsurface, including buried faults, folds, salt domes, and the size, shape, and orientation of rock layers. They are collected by using truck-mounted vibrators or dynamite (onshore), or air guns towed by ships (offshore), to generate sound waves; these waves travel into the Earth and are reflected by underground rock layers; instruments at the surface record these reflected waves; and the recorded waves are mathematically processed to produce 2-D or 3-D images of subsurface features. These images, which cover many square miles and have a resolution of tens to hundreds of feet, help to pinpoint the areas most likely to contain oil and/or gas.

A typical setup for offshore seismic imaging. Image Credit: U.S. Bureau of Ocean Energy Management.2

Mapping the Subsurface 2: Local Data from Well Logs, Samples, and Cores

Drilling a small number of exploratory holes or using data from previously drilled wells (common in areas of existing oil and gas production) allows geologists to develop a much more complete map of the subsurface using well logs and cores:

  • well log is produced by lowering geophysical devices into a wellbore, before (and sometimes after) the steel well casing is inserted, to record the rock’s response to electrical currents and sound waves and measure the radioactive and electromagnetic properties of the rocks and their contained fluids.3 Well logs have been used for almost 100 years4 and are recorded in essentially all modern wells.

  • core is a cylindrical column of rock, commonly 3-4 inches in diameter, that is cut and extracted as a well is drilled. A core provides a small cross-section of the sequence of rocks being drilled through, providing more comprehensive information than the measurements made by tools inside the wellbore.5 Core analysis gives the most detailed information about the rock layers, faults and fractures, rock and fluid compositions, and how easily fluids (especially oil and gas) can flow through the rock and thus into the well.

By comparing the depth, thickness, and composition of subsurface rock formations in nearby wells, geoscientists can predict the location and productive potential of oil and gas deposits before drilling a new well. As a new well is being drilled, well logs and cores also help geoscientists and petroleum engineers to predict whether the rocks can produce enough oil or natural gas to justify the cost of preparing the well for production.7

A box containing 9 feet of 4-inch diameter core from the National Petroleum Reserve, Alaska, showing the fine-scale structure and composition of the rock layers being drilled. Image Source: U.S. Geological Survey.6

Data Preservation

Preservation of subsurface data is an ongoing challenge, both because there is so much of it and because a lot of older data predate computer storage. A modern seismic survey produces a few to thousands of terabytes of data;8 state and federal repositories collectively hold hundreds of miles of core;9 and millions of digital and paper records are housed at state geological surveys. For example, the Kansas Geological Society library maintains over 2.5 million digitized well logs and associated records for the state.10 Oil companies also retain huge stores of their own data. Preserving these data, which cost many millions of dollars to collect, allows them to be used in the future for a variety of purposes, some of which may not have been anticipated when the data were originally collected. For example, the shale formations that are now yielding large volumes of oil and natural gas in the United States were known but not considered for development for decades while conventional oil and gas resources were being extracted in many of the same areas. Archived well logs from these areas have helped many oil and gas producers to focus in on these shale resources now that the combination of hydraulic fracturing and horizontal drilling allow for their development.

Data for Hazard Mitigation

Oil and gas exploration is a major source of information about the subsurface that can be used to help identify geologic hazards:

  • Since 2013, the oil and gas industry has provided more than 2,500 square miles of seismic data to Louisiana universities to assist with research into the causes and effects of subsidence in coastal wetlands. For example, seismic and well data have been used to link faults to historic subsidence and wetland loss near Lake Boudreaux.11

  • To improve earthquake risk assessment and mitigation in metropolitan Los Angeles, scientists have used seismic and well data from the oil and gas industry to map out previously unidentified faults. This work was motivated by the 1994 Northridge earthquake, which occurred on an unknown fault that was not visible at the Earth’s surface.12

More Resources

U.S. Geological Survey – National Geological and Geophysical Data Preservation Program.

References

1 U.S. Energy Information Administration (2016). Trends in U.S. Oil and Natural Gas Upstream Costs.
2 Bureau of Ocean Energy Management – Record of Decision, Atlantic OCS Region Geological and Geophysical Activities.
3 Varhaug, M. (2016). Basic Well Log Interpretation. The Defining Series, Oilfield Review.
4 Schlumberger – 1920s: The First Well Log.
5 AAPGWiki – Overview of Routine Core Analysis.
6 Zihlman, F.N. et al. (2000). Selected Data from Fourteen Wildcat Wells in the National Petroleum Reserve in Alaska. USGS Open-File Report 00-200. Core from the well “East Simpson 2”, Image no. 0462077.
7 Society of Petroleum Engineers PetroWiki – Petrophysics.
8 “Big Data Growth Continues in Seismic Surveys.” K. Boman, Rigzone, September 2, 2015.
9 U.S. Geological Survey Core Research Center – Frequently Asked Questions.
10 Kansas Geological Society & Library – Oil and Gas Well Data.
11 Akintomide, A.O. and Dawers, N.H. (2016). Structure of the Northern Margin of the Terrebonne Trough, Southeastern Louisiana: Implications for Salt Withdrawal and Miocene to Holocene Fault Activity. Geological Society of America Abstracts with Programs, 48(7), Paper No. 244-2.
12 Shaw, J. and Shearer, P. (1999). An Elusive Blind-Thrust Fault Beneath Metropolitan Los Angeles. Science, 283, 1516-1518.

Date updated: 2018-06-01
Petroleum and the Environment, Part 23/24
Written by E. Allison and B. Mandler for AGI, 2018

Optimizing pump reliability and performance

Optimizing pump reliability and performance

The offshore industry faces two main challenges: maximizing production within the limits of the reservoir, and minimizing operational costs while maintaining the safety of the platform. Pumps form one of the main groups of equipment that influence the outcome of both challenges and they require expert knowledge to ensure continued reliability and performance.

Murray Wilson, Sulzer UK argues that in each case, industry engineering expertise and commercial innovation are required to deliver these goals. Furthermore, the capital expenditure to improve reliability is most often far outweighed by the costs incurred by an unexpected failure and the subsequent costs of lost production. By taking a proactive approach and involving an expert maintenance provider, platform operators can deliver significant benefits to the business in the long term.

Improving performance

In the years following commissioning, the actual duty requirements of production pumps are likely to change – production rates may start to decline after the initial plateau period or the connection of additional wells may mean that potential production is being limited by the processing trains which were designed for lower volumes.

As equipment is pushed to operate significantly outside of its original design envelope, this can often cause operating problems which impact reliability and ultimately affect platform production. This also results in increased maintenance costs as operators and equipment specialists are required to overhaul plant more frequently.

Ultimately, the goal is to improve reliability and efficiency while reducing downtime and energy consumption, at the same time as satisfying API, ATEX, and many other engineering standards. However, this seemingly impossible task can be achieved through the implementation of preventative maintenance techniques and the adoption of the latest engineering designs for pumps.

Water injection pumps, seawater lift pumps, crude oil offloading pumps and fire suppression systems all require individual designs to deliver the best efficiency and productivity. At the same time, they also need specialist maintenance routines that will prolong reliability and effectiveness.

Proactive maintenance

A proactive maintenance regime is crucial to identifying potential issues before they develop into problems. However, this requires knowledgeable and experienced personnel to carry out the in-situ platform maintenance and these skills take time to perfect. The time required for this process can be greatly reduced by instigating a training program prepared by experts in equipment maintenance, who can pass on their collective knowledge in a structured and efficient manner.

In terms of through-life maintenance cost, preventative action is almost always less costly than corrective action, and adopting a carefully managed, proactive regime is crucial to identifying potential issues before they develop into problems. Two of the most prominent symptoms that occur prior to failure in mechanical and electrical equipment are increasing vibration and rising operational temperature.

Regular trending and analysis of radial and axial vibration signatures and thermographic/visual inspections of bearings, coils and electrical connections can prove invaluable. The latest developments in operational monitoring can be applied to existing assets and then used to determine the optimal point at which planned maintenance should be conducted.

Understanding cavitation

Most commonly seen on the pump impeller, cavitation is caused by a pressure difference, either on the pump body or the impeller. A sudden pressure drop in the fluid causes the liquid to flash to vapor when the local pressure falls below the saturation pressure for the fluid being pumped. Any vapor bubbles formed by the pressure drop are swept along the impeller vanes by the flow of the fluid. When the bubbles enter a region where the local pressure is greater than saturation pressure, the vapor bubbles abruptly collapse, creating a shockwave that, over time, can cause significant damage to the impeller vanes or pump housing.

In most cases, it is better to prevent cavitation rather than trying to reduce the effects on the pumping equipment. This is normally achieved by one of the three actions:

  • Increase the suction head

  • Lower the fluid temperature

  • Decrease the Net Positive Suction Head Required (NPSHR)

For situations where cavitation is unavoidable, or the pumping system suffers from internal recirculation or excessive turbulence, it may be necessary to review the pump design or minimize the potential for damage using a bespoke coating system.

Tackling erosion

The offshore production environment exposes pumps to harsh operating conditions and the abrasive nature of the fluids being pumped in certain processes on board can ultimately result in reduced efficiency and decreased pump performance.

Produced Water Re-injection pumps that are employed to force water back into the oil field and thus maintain the reservoir pressure needed to lift the oil to the surface are often subjected to high levels of abrasion. This is commonly the result of sand carryover from upstream filtration where there has been a process upset or where filtration systems are not adequate. Pumps that are used to transfer these fluids can experience significant levels of erosion, especially in areas with high flow velocities. The entrained sand particles act as an abrasive and higher working pressures only serve to compound the issue.

Pump manufacturers will aim to minimize flow velocities throughout the pump or design it in such a way that the flow velocities through close-running clearances are as low as practically possible within the duty for which the product has been designed. Under these circumstances, one of the most effective solutions is the use of specialist protective coatings, which can be used to protect selected areas in the pump.

Delivering the best coating system

With so many benefits arising from a specialist coating, it is important to determine the most appropriate materials, equipment and application procedures, otherwise the coating may degrade and fail prematurely. The processes and specifications used by companies such as Sulzer for applying coatings have been developed over many years and are essential to delivering a durable and reliable product.

To illustrate the importance of these procedures, especially in pump applications, consider the process of installing and removing an impeller. In many situations, the impeller is heated to allow it to be installed or removed from the drive shaft. This shrink-fit procedure can cause inappropriate coatings to be damaged during a routine maintenance operation. Sulzer has ensured that its coating technologies can withstand this thermal shock and continue to deliver long-lasting corrosion protection.

The importance of engineering expertise should not be underestimated and the benefits of engaging an experienced and well-resourced pump engineering company should not be overlooked. When dealing with complex engineering design, as seen in many pumping applications, it is very important to select to most effective and efficient resources to deliver a repair or refurbishment.

Meeting the logistical challenge

When it comes to complex equipment such as the large pumps encountered on offshore platforms, the most efficient delivery of maintenance will come from a provider of turnkey rotating equipment solutions. These organizations should have the necessary service facilities, trained & competent staff, logistical support and the service culture needed to support production critical plant.

In an ideal world, all the maintenance would be carefully planned and managed, but often it is necessary to respond to a situation immediately and deliver technical support, equipment, and materials at a moment’s notice. With a global network of service centers, capable of designing and manufacturing custom parts, Sulzer has not only the expertise but also the facilities and resources to meet the challenges faced by the offshore industry.

As a world-leading pump manufacturer, Sulzer offers state-of-the-art design and manufacturing facilities for oil and gas production, including subsea applications. This expertise is transferred throughout the company and used to support the maintenance and repair of any type of pumping asset.

 

Editorial contact: DMA Europa Ltd. : Philip Howe
Tel: +44 (0)1562 751436 Fax: +44 (0)1562 748315
Web: www.dmaeuropa.com
Email: [email protected]
Address: Europa Building, Arthur Drive, Hoo Farm Industrial Estate Kidderminster, Worcestershire, DY11 7RA, UK

Reader contact: Sulzer Turbo Services Houston Inc. :  Jennifer Cardillo, Marketing and Communications Manager, Americas Rotating Equipment Services
Tel: +1 713 567 2706 Fax:
Web: www.sulzer.com
Email: [email protected]sulzer.com
Address: Sulzer Turbo Services Houston Inc. 11518 Old La Porte Road La Porte, TX 77571 USA

 

About Sulzer:Sulzer is the leading worldwide, independent service provider for the repair and maintenance of rotating machines including turbomachinery, pumps and electro-mechanical equipment. With a global network of over 180 technically advanced manufacturing and test facilities, Sulzer offers a collaborative advantage that delivers high-quality, cost-effective, customized and turnkey solutions, providing its customers with the peace of mind to focus on their core operations.

Sulzer Rotating Equipment Services, a division of Sulzer, can accommodate all brands of rotating equipment including turbines, compressors, generators, motors, and pumps. With an enviable track record, dedicated teams of on-site engineers provide best-in-class solutions to ensure that the most effective service is delivered.

Sulzer is dedicated to providing superior service solutions to a range of industries including power generation, oil and gas, hydrocarbon and chemical processing, water, and air separation. Every solution is customized to suit the business needs of each application – whenever or wherever that may be.

With a long history of providing engineering service support, Sulzer is headquartered in Winterthur, Switzerland where it began in 1834. Today, with sales over US$ 3 billion and with approximately 14,000 employees, the Sulzer footprint spans across the globe. The core aim is to deliver a flexible and cost-effective service that optimizes customer operational efficiency and minimizes downtime.

For more information on Sulzer, visit www.sulzer.com

The image(s) distributed with this press release may only be used to accompany this copy, and are subject to copyright. Please contact DMA Europa if you wish to license the image for further use.

Visit the DMA Europa website for the full text in PDF format and the associated high-resolution image and video files: Website

How to achieve technology innovation in the oil and gas industry

Many industries have exploited the exciting opportunities to create new products and markets, but the oil and gas sector has lagged behind and has resulted in the oil and gas industry failing to exploit the potential of new technologies

The oil and gas industry is now at a pivotal point in its evolution and we are now on the cusp of a transformation. The rise of new technologies, coupled with the ongoing global push for a reduced environmental impact, is altering the industry. Organisations across the sector face growing pressure to streamline their operations in order to improve overall efficiency and unlock additional barrels of oil to maximize revenue.

Despite these new hurdles, the oil and gas sector has been generally very slow compared to other industries when it comes to leveraging the potential of new technologies to innovate and optimize the performance of its systems. While companies have tackled the lower oil price with positive actions to reduce environmental impact, lower operating costs and increase efficiency, these gains must now be made sustainable, Therefore, we must truly transform the way we work.

See also: How can drones power the offshore oil and gas operations?

In light of these challenges, it is now vital that players, both new and old, fully embrace the potential of new solutions to kickstart the sector’s technological revolution and achieve the higher level of stability it desperately needs. Research conducted by McKinsey & Company found that the effective use of digital technologies across the industry could lower capital expenditures by up to 20%, reduce operating costs in upstream by 3 to 5% and by about half that that in downstream, demonstrating the clear cost-savings opportunities and efficiency to be had.

Investment in today’s visionaries for tomorrow

With new technologies emerging every day, many with the same promise of reducing costs and optimizing a business’ performance, ways to achieve technological advancement across the industry are now in abundance and oil executives must consider how best to accelerate this innovation to ensure its continued success on a global scale.

At the core of most of today’s technological innovation is either a desire or need to solve a particular problem. This way of thinking is often demonstrated best by those with a different vision of the industry’s future, who are able to identify the areas needing improvement and develop new solutions accordingly. The current oil and gas sector is no exception, and we are now seeing a rapid increase in the number of emerging oil and gas startups looking to move the industry away from its traditional practices and towards a new and more efficient way of operating.

In an industry where innovation is now the key to sustainability, the ‘if it isn’t broke, don’t fix it’ approach to development will no longer suffice. Larger companies must refocus much of their investment on the smaller, more ambitious technology developers to ensure revolutionary solutions enter the oil and gas market faster and enable them to prepare their existing solutions for success within a new era of innovation.

See also: 3 industries saving billions with cognitive machine learning

Accelerating changes to how we work and embracing new technologies will, therefore, be at the heart of the industry’s transformation; improving productivity, increasing efficiency and creating well-paid jobs. That said, it still vital that companies continue to balance this level of innovation with their existing knowledge of best practice for oil and gas organizations, to ensure a consistent position within the industry of both today and tomorrow.

One particular concept we have seen emerge across the oil and gas industry within the last decade is the digital oilfield, which refers to the real-time automation of operations through a combination of business process management systems and complex information technology, to ensure the simple management and tracking of the data. This has presented oil and gas companies with one way to streamline systems and achieve technology innovation, however, a greater investment in startups could see many other opportunities come to fruition. This means we must have a technology vision for the industry and a future where remote operations and automation are the norm.

Embracing a collaborative approach

One of the biggest challenges for oil and gas companies when achieving this degree of innovation on an industry-wide scale is finding the best way to integrate ground-breaking, new technologies. Embracing a more collaborative amongst new entrants and existing players is essential for streamlining the oil and gas landscape, reducing costs and overcoming the current lack of widespread technological development across the sector.

Partnered with a clear strategy for implementing this innovation across their business model, a greater convergence between the old and new will ensure companies are taking the best solutions from across the industry, not only to achieve innovation but to also give them a greater competitive edge within an increasingly in-demand and saturated market. This will require the industry, technology providers, government, regulators all working in partnership to deliver the technology transformation.

See also: Embracing hybrid cloud services in traditional industries

This kind of approach can provide huge benefits for all involved. For startups looking to enter the space, it can help them to connect with major investors and bring their solutions to market quickly and successfully as a result of increased investment, facilities, and resources. For the larger companies looking to invest in technology-driven solutions, this can help to change their outlook on their existing infrastructure and help to fill any technology gaps with revolutionary companies and products.

Oil and gas technology has not yet been at the forefront of the global innovation agenda, yet with demand for these services increasing every day, it is becoming increasingly ranked as a priority for change in many countries worldwide. It is now time to fully kick-start the industry’s technological revolution and the key to achieving this lies within the hundreds of emerging solutions being created by developers striving for sustainability and efficiency.

 

Originally published on Information Age 

Sourced by David Millar, TechX director, the Oil & Gas Technology Centre

PRESS RELEASE: ExxonMobil to Join Oil and Gas Climate Initiative

ExxonMobil to Join Oil and Gas Climate Initiative
  • The CEO led global initiative aims to provide practical solutions to climate change mitigation

  • Focus areas include carbon capture and storage, methane reductions, energy efficiency

  • As part of the initiative, ExxonMobil to invest in research and development of long-term solutions to reduce greenhouse gas emissions

IRVING, Texas–(BUSINESS WIRE)–ExxonMobil today said it will join the Oil and Gas Climate Initiative (OGCI), a voluntary initiative representing 13 of the world’s largest oil and gas producers working collaboratively toward solutions to mitigate the risks of climate change.

“It will take the collective efforts of many in the energy industry and society to develop scalable, affordable solutions that will be needed to address the risks of climate change”

The CEO-led organization focuses on developing practical solutions in areas including carbon capture and storage, methane emissions reductions and energy and transportation efficiency. As part of the initiative, ExxonMobil will expand its investment in research and development of long-term solutions to reduce greenhouse gas emissions as well as partnerships and multi-stakeholder initiatives that will pursue lower-emission technologies.

“It will take the collective efforts of many in the energy industry and society to develop scalable, affordable solutions that will be needed to address the risks of climate change,” said Darren Woods, chairman, and chief executive officer of ExxonMobil. “Our mission is to supply energy for modern life and improve living standards around the world while minimizing impacts on the environment. This dual challenge is one of the most important issues facing society and our company.”

ExxonMobil has invested billions of dollars in researching and developing lower-emission solutions, including carbon capture and storage technology, next-generation biofuels, cogeneration, and more efficient manufacturing processes.

Earlier this year, ExxonMobil announced initiatives to lower greenhouse gas emissions associated with its operations by 2020, including reducing methane emissions 15 percent and flaring by 25 percent. Since 2000, ExxonMobil has spent more than $9 billion to develop and deploy higher-efficiency and lower-emission energy solutions across its operations.

OGCI was established following the 2014 World Economic Forum and formally launched at the United Nations Climate Summit the same year. Members include BP, Chevron, CNPC, Eni, Equinor, ExxonMobil, Occidental Petroleum, Pemex, Petrobras, Repsol, Royal Dutch Shell, Saudi Aramco, and Total.

About ExxonMobil

ExxonMobil, the largest publicly traded international energy company, uses technology and innovation to help meet the world’s growing energy needs. ExxonMobil holds an industry-leading inventory of resources, is one of the largest refiners and marketers of petroleum products and its chemical company is one of the largest in the world. For more information, visit www.exxonmobil.com or follow us on Twitter www.twitter.com/exxonmobil.

Cautionary Statement: Statements of future events or conditions in this release are forward-looking statements. Actual future results, including the timing, results and impact of new technologies and future emission reductions, could differ significantly depending on the outcome of further research and testing; the development and competitiveness of alternative technologies; the ability to develop and scale pilot projects on a cost-effective basis; political and regulatory developments; and other factors discussed in this release and under the heading “Factors Affecting Future Results” on the Investors page of ExxonMobil’s website at exxonmobil.com.

Contacts

Exxon Mobil Corporation
Media Line, 972-940-6007

Source: Business Wire

While politicians court Google and Uber, fracking industry offers a different sort of high-tech job

CANNONSBURG, Pa. — If there is mud on the floor, they say in the shale industry, that means cash is coming in the door. That is, when workers are out in the field and the boots are getting dirty, money is being made.

Thanks to an infusion of high technology driving the natural gas industry, it’s not just about dirty boots anymore – and it’s a good story. It’s a marriage of advanced technologies and dirt-under-your-nails hard work rarely told, because extracting shale is not a popular business politically.

Fracking, it turns out, is the one high-tech industry not embraced by politicians in Pittsburgh who are rushing to embrace the likes of Uber and Google. Why? Because local progressive Democrats, very vocal climate activists, and the burgeoning Democratic Socialists of America party demand a wholesale repudiation of the natural gas industry. Local Democratic officials thus have to oppose fracking or risk losing in a Democratic primary.

Vice President of Engineering and Development of CNX Resources Corporation Andrea Passman stands in a control room that is used for predicting drilling locations at CNX's headquarters on July 30 in Cannonsburg, Pa.

Vice President of Engineering and Development of CNX Resources Corporation Andrea Passman stands in a control room that is used for predicting drilling locations at CNX’s headquarters on July 30 in Cannonsburg, Pa.

(Justin Merriman for the Washington Examiner)

Today’s natural gas industry isn’t the same petroleum job your grandfather or your father would have applied for. It not only attracts computer scientists, software engineers, mathematicians, and geologists to relocate to Western Pennsylvania from around the country, but it also provides careers for locals who thought those good jobs left for good when the coal mines and steel mills closed a generation ago.

Plenty of locals, who perhaps were not cut out for college, just wanted an opportunity to work hard in an industry with a future. All the better if that industry utilized the resources of the land while conserving it — nobody wants to spoil the places for hunting, fishing, climbing, hiking, and camping. Even better, a local job would allow them to live near family.

Mike May is one such guy.

The 33-year-old grew up in Imperial, Pa., along the Lincoln Highway. After graduating from West Allegheny High School, May joined the Marines. When he left the service, he wanted to come back home to Western Pennsylvania and work his way up in the world, but he just didn’t know if he had the career skills.

Mike May, 33, of Oakdale, Pa., works in the control room of CNX Resources Corporation on July 30 at their headquarters in Cannonsburg, Pa. The control room is able to monitor and adjust well sites throughout several states.

Mike May, 33, of Oakdale, Pa., works in the control room of CNX Resources Corporation on July 30 at their headquarters in Cannonsburg, Pa. The control room is able to monitor and adjust well sites throughout several states.

(Justin Merriman for the Washington Examiner)

“So, I started in the gas and oil fields literally working with my hands; I have worked in the industry from the bottom up,” he says as he stands in front of three monitors doing the same thing he did in the field.

No dirt under the nails. No weather dictating field conditions. No mud on the boots. Just precision automation that does the job a team of workers used to do in the field. Now, May does it inside the offices of CNX, a fracking company that broke off of energy giant CONSOL.

“Basically, I was a production operator,” explains May, “I ran all the physical operations, manual chokes, fixing anything that would break or go down; adjusting water dumps to increase the efficiency of the separators, water, and tank levels out there,” he says of the drilling sites.

Now, he does almost all of that remotely.

“See, this is the digital twin of the well site,” he says, pointing to one of several screens he is monitoring in a highly secure floor of the complex. “So, over here, we have all of our physical assets. This is the data surveillance side of the house. We’re also able to control and push parameters out to the field level. So, things I used have to do at the site and make physical changes I can do using technology,” he says.

Twenty miles north of this office, in Pittsburgh, several dozen young climate activists — about May’s age — protested last week in front of the mayor’s office. They pressed Democratic city and county leaders to stop the expansion of fracking in the county and to speak out against the Shell cracker plant under construction in the region.

Twenty miles in the opposite direction, public high schools are offering vocational training for their students that prepare them to walk off the high school football field on graduation day with their diplomas and into jobs that start at $129,000 a year.

Compared to the kids closer to Pittsburgh, these kids from rural high schools won’t have an inside track for jobs at the likes of Google, Uber, and others whom the Democratic mayor celebrates as part of the “new Pittsburgh.”

And the Shell cracker plant the climate activists were protesting? It doesn’t make really make crackers — cracking is the process that converts natural gas products into ethylene and then into plastics. The $6 billion dollar plant began construction last year, with construction employment expected to exceed 6,000 workers over the next ten years and provide 600 permanent positions once the plant is complete.

Since the 1920s, technology and automation have been disrupting the manufacturing world — eliminating jobs and growth opportunities throughout the different regions in the country. Here, technology is creating jobs. For May, automation and high technology didn’t take his job; it enriched it.

“Correct. I kinda evolved with the times. I am truly living the American Dream.”

Video

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Published on Jun 6, 2016

YouTube 

Petroleum Institute announces ‘Explore Offshore’ coalition

TALLAHASSEE — Proponents of drilling for oil and natural gas haven’t given up on tapping areas closer to Florida’s shoreline despite repeated assurances those waters will be exempt from a White House plan to expand exploration.

The Washington, D.C.-based American Petroleum Institute announced Wednesday a multi-state “Explore Offshore” coalition to support the Trump administration’s plan to open previously protected parts of the Atlantic Ocean and the eastern Gulf of Mexico to oil and gas drilling.

The coalition’s Florida team, which is focused on the eastern Gulf waters, includes former Lt. Gov. Jeff Kottkamp, former Okaloosa County Commissioner Wayne Harris, former Puerto Rico state Sen. Miriam Ramirez and Florida Petroleum Council Executive Director David Mica.

Mica said Floridians use more than 25 million gallons of motor fuel a day, while the industry is restricted from “some very, very good areas” that potentially have oil.

We need to do it in an environmentally responsible manner, but we must go forward,” Mica said. “I think that it’s really putting your head in the sand if you think that we’re not going to need a lot more oil and gas into the future and that we can rely only on alternative fuels.”

Many Florida officials, including Gov. Rick Scott, Department of Environmental Protection Secretary Noah Valenstein and members of Florida’s congressional delegation from both sides of the political aisle have denounced the possibility of opening to drilling almost all of the nation’s outer continental shelf — a jurisdictional term describing submerged lands 10.36 statutory miles off Florida’s west coast and 3 nautical miles off the east coast.

Interior Secretary Ryan Zinke appeared briefly Jan. 9 in Tallahassee to announce drilling would not occur off the Florida coast. But the Trump administration’s stance has not been formalized and continues to draw questions.

U.S. Sen. Bill Nelson, D-Fla., on Wednesday equated the petroleum industry’s new coalition with lingering skepticism over Zinke’s assurances that waters off the Florida coast will be exempt from the plan.

“Here we go. Like us, Big Oil doesn’t believe Florida is really ‘off the table’ to new drilling — despite what Scott and the Trump Administration keep saying — and now they are making a new push to drill closer to Florida’s shores,” Nelson tweeted. “We can’t let that happen!”

The federal Bureau of Ocean Energy Management is expected to release a draft report on the offshore proposal before the end of the year. That will kick off the second round of public hearings.

Drilling proponents have hailed the prospects of exploring for oil and gas closer to shore as benefiting consumers by potentially creating jobs and additional government revenue while strengthening national security.

The American Petroleum Institute said its coalition features more than 100 businesses, organizations and officials from Virginia, North Carolina, South Carolina, Georgia and Florida.

In its release, the institute highlighted Florida’s dependence on natural gas, which generates 67 percent of the state’s electricity, and forecast that offshore development could result in $2.6 billion in private investment in Florida and $1 billion per year in state revenues.

Kottkamp said the “availability of affordable energy is critical” to Florida’s quality of life.

“We look forward to working with our local leaders to discuss ways to maintain our state’s natural beauty while at the same time expanding opportunities to keep our nation energy independent,” Kottkamp said in a statement.

In November, Florida voters will decide whether to approve a proposed constitutional amendment that would ban nearshore oil and gas drilling. That ban would affect state-controlled waters.

Source: Panama City News Herald

Video

The Reality of Digital in Oil & Gas

What does digitization mean for the oil and gas industry?

Digital has been the big buzz word in the industry for some time now – but what exactly does it mean. McKinsey & Company Senior Partner Matt Rogers sat down with the Financial Times US Industry and Energy Editor, Ed Crooks in the first of the Digital Dialogues in Oil & Gas series to discuss the impact of digital in the industry.

Ed Crooks

Ed Crooks

US Industry and Energy Editor

FINANCIAL TIMES

See bio 

Matt Rogers

Matt Rogers

Senior Partner

MCKINSEY & COMPANY

The Financial Times is one of the world’s leading business news organizations, recognized internationally for its authority, integrity, and accuracy. In 2016 the FT passed a significant milestone in its digital transformation as digital and services revenues overtook print revenues for the first time. The FT has a combined paid print and digital circulation of more than 910,000 and makes 60% of revenues from its journalism.

The McKinsey Center for Future Mobility was created to help business leaders and policymakers come to terms with a future that is increasingly autonomous, connected, electrified, and shared. Based in four global hubs (Beijing, Detroit, Munich, and Silicon Valley), our forward-thinking and integrated perspective, industry expertise, proprietary research, and global convening power give us a unique combination of assets to help clients navigate the mobility revolution.

www.mckinsey.com

August 2018, McKinsey & Company, www.mckinsey.com. Copyright (c) 2018 McKinsey & Company. All rights reserved. Reprinted by permission.

Frost & Sullivan Identifies the Top 5 Industry Shifts Fueling the Future of Drilling Systems

Blockchain, AI Technologies to Increase Upstream Operational Efficiency

SANTA CLARA, CaliforniaAug. 8, 2018 /PRNewswire/ — Frost & Sullivan’s recent analysis, The Future of Drilling Systems, highlights the rise of disruptive technologies such as blockchain, additive manufacturing, and Artificial Intelligence (AI) and how they are setting the stage for large-scale gains in operational and cost efficiencies in the drilling sector. Intelligent, automated drilling systems demonstrably have a huge impact on the drilling rig count and cost per well drilled as they require fewer on-site workers and boost the efficiency of people still on location. In addition, these systems proactively conduct maintenance to decrease non-productive time (NPT) and critical failures.

The analysis also provides an overview of emerging technology areas, industry shifts, company profiles, and resulting business model transformations in drilling activities through 2025. It presents clients with a holistic, directional analysis of the drilling ecosystem, with a focus on onshore operations.

For further information on this analysis, please visit: http://frost.ly/2o1

“Next-generation automated drilling systems can drastically reduce the time spent on reporting, record keeping, and compliance by integrating technologies such as advanced computing, advanced sensors, and computer vision,” said Chirag Rathi, Energy & Environment Consulting Director at Frost & Sullivan. “While robotics will leverage sensors and digital twins, blockchain can aid in parts ordering and logistics. Similarly, additive manufacturing can help create parts, augmented reality (AR) can handle maintenance, and the whole system can be coordinated through cognitive computing.”

The new upstream methods are expectedly triggering novel business models and altering the value chain. For instance, contractors and service providers are consolidating vertically to expand their offerings to provide proprietary, all-in-one solutions. In due time, legacy rig fleets will be rationalized and integrated across a holistic automation platform, which, in turn, will stoke industry demand for open systems architecture.

“The rising relevance of digitally enabled business models will coincide with the increasing importance of data in influencing procurement decisions. The net result will be a highly transparent and quantifiable value chain,” noted Rathi. “The greatest industry impact will be felt when an AI-driven platform that automates procurement across all drilling and support activities emerges as a trusted, secure, third-party application encompassing the entire drilling ecosystem.”

The drilling industry is clearly in the midst of a digital transformation. Among the numerous big and small industry shifts, the five that stand out are:

  1. Data-driven decision making: As actionable data replace human judgment, Big Data analytics combined with machine learning and other AI techniques will enable smarter automation, streamlined workflows, and optimized supply chains for higher operational efficiencies.

  2. Shifting workforce composition: An aging workforce will be replaced by digital natives, prompting enthusiastic adoption of digital solutions.

  3. Digitally enabled business models: Upstream will move beyond fixed day-rate models as operators peg rates against micro-fluctuations in a range of benchmarks. This will promote data-validated performance over other contracting considerations such as brand or relationship history.

  4. Accelerating the pace of innovation: The push for open systems architecture will fuel innovation-based competition.

  5. Value chain disruptions: Operators are acquiring suppliers to lower costs. Eventually, they may take over drilling responsibilities due to the potential of automation to diminish costs and liability risks.

The Future of Drilling Systems is part of Frost & Sullivan’s global Oil & Gas Innovation Council.

About Frost & Sullivan

For over five decades, Frost & Sullivan has become world-renowned for its role in helping investors, corporate leaders and governments navigate economic changes and identify disruptive technologies, Mega Trends, new business models and companies to action, resulting in a continuous flow of growth opportunities to drive future success

Contact us: Start the discussion.

Contact:
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SOURCE Frost & Sullivan

AkerBP, Cognite and Solution Seeker have entered into a partnership agreement to leverage artificial intelligence (AI) for real-time, data driven production optimization.

First out is the Alvheim field, where Solution Seeker´s ProductionCompass AI solution will utilize all available and relevant data to perform real-time production data analytics and production optimization, including management of the challenging slugging problem at the field through advanced slug data analytics.

“With Alvheim, we embark on a very exciting journey with AkerBP and Cognite to deliver artificial intelligence to maximize oil and gas production based on pure data-driven models. We are honored and proud to be chosen as a strategic partner to AkerBP and Cognite, as AkerBP is clearly one of the most ambitious oil companies driving the digital oilfield agenda.” says Vidar Gunnerud, founder, and CEO of Solution Seeker.

The production data is streamed live from Cognite´s Data Platform, developed in close collaboration with AkerBP to make all data and models readily accessible for all users and systems. The platform facilitates an open ecosystem for advanced applications such as Solution Seeker´s AI.

“We believe Solution Seeker´s AI will enable us to fully leverage and make sense of all our production data, build robust, fast and precise prediction models, and maximize our production in real-time. Their solution plugs directly onto the Cognite Data Platform, accessing all relevant production data, and writing all relevant results from their artificial intelligence back to the platform so other systems and users, in turn, can utilize these new data. In addition to the value this project creates from production optimization, this is a real demonstration of how we want to work with partners through the Cognite platform. This is data liberalization in practice – creating tangible results at every step,” says Signy Vefring, Manager Digitalization Program Office at AkerBP.

Solution Seeker is developing the first artificial intelligence for oil and gas production optimization, leveraging big data and machine learning techniques to solve the continuous optimization problem. The AI is capable of analyzing thousands of historical and live production data streams, identifying field behavior and relations, and automatically and continuously providing the most up to date prediction model to make the optimal choice of production settings.

The AI is currently being developed and deployed in collaboration with ConocoPhillips, Neptune Energy, Wintershall, Lundin, and AkerBP, and will be launched and made commercially available to all operators in 2018. This will disrupt the way operators can maximize production and improve their operations.

Solution Seeker is a technology spin-off from the ICT research group at NTNU Engineering Cybernetics and NTNU’s Centre for Integrated Operations.

Read more about this on Sysla (in Norwegian).

Video

Turn off the light!

The Crude Life Interview: Bill Wren, The University of Texas at Austin

Bill Wren, The University of Texas at Austin, explains how The University of Texas at Austin’s McDonald Observatory and the collaboration with the Permian Basin Petroleum Association (PBPA) and the Texas Oil and Gas Association (TXOGA) to reduce light shining into the sky from drilling rigs and related activities in West Texas. The excess light has the potential to drown out the light from stars and galaxies and threatens to reduce the effectiveness of the observatory’s research telescopes to study the mysteries of the universe.

Source: The Crude Life Content Network

YouTube

 

Science-based Collaboratory Brings Diverse Stakeholders Together to Study Methane Emissions from Natural Gas

A new industry-led collaborative research consortium will work to advance methane science to better understand global methane emissions and the need for additional solutions.

The Collaboratory for Advancing Methane Science (CAMS) will pursue scientific studies addressing methane emissions from all sectors along the entire natural gas value chain, from production to end use. Studies will focus on detection, measurement, and quantification of methane emissions with the goal of finding opportunities for reduction.

GTI will serve as the program administrator for the effort with initial participants from leading energy companies Cheniere, Chevron, Equinor, ExxonMobil, and Pioneer Natural Resources, and plans to expand participation to include other companies from across the natural gas value chain. Through scientific studies, CAMS will bring together a diverse group of experts from industry, academia, and federal and state agencies to deliver factual data that can be used to inform regulations and policy development.

GTI will manage the overall program, including individual research projects. CAMS members, with input from an independent Scientific Advisory Board, will prioritize and fund research. CAMS will focus on effectively communicating findings to program stakeholders and the general public. Results will be independently published by the research project team in peer-reviewed scientific journals.

“This is an important collaboration between industry, academia, government, and researchers,” said Amol Phadke, vice president, safety and sustainability for U.S. and Mexico operations, Equinor. “It is a great opportunity to work together in understanding emissions across the value chain, giving us a more complete picture of how we can continue to reduce methane from our operations.”

“As a leading energy company, we are committed to continually reducing methane emissions,” said Sara Ortwein, president of XTO Energy, a subsidiary of ExxonMobil. “The right partnerships are critical for success, and participating in CAMS will expand industry learning on solutions that can make a difference.”

“The use of natural gas is already reducing carbon dioxide and traditional air pollutants in the United States and around the world, but further reduction of methane emissions greater amplifies the positive impact of natural gas,” said Chris Smith, SVP for Policy, Government and Public Affairs at Cheniere, the largest U.S. exporter of LNG. “Supporting peer-reviewed science is an important first step as we look for ways to encourage the reduction of methane emissions throughout the domestic natural gas value chain.”

The research will complement recent methane emissions studies sponsored by government agencies and academia, and build on lessons learned from that body of work. New tools and technologies to better detect leaks and characterize emissions will be evaluated, and practical solutions for emissions reduction will be identified.

6/25/18 Des Plaines, IL

Source: The Collaboratory to Advance Methane Science (CAMS) 

 

Decarbonization of industrial sectors: the next frontier

In the Paris Agreement of 2015, member states agreed to limit global warming to 2 °C versus pre-industrial levels. This would imply reducing greenhouse gas (GHG) emissions by 80 to 95 percent of the 1990 level by 2050. As industry accounted for about 28 percent of global greenhouse gas emissions in 2014, it follows that these targets cannot be reached without decarbonizing industrial activities. Industrial sites have long lifetimes; therefore, upgrading or replacing these facilities to lower carbon emissions requires that planning and investments start well in advance.

In this report, we investigate options to decarbonize industrial processes, especially in the cement, steel, ethylene, and ammonia sectors. We selected these sectors because they are hard to abate, due to their relatively high share of emissions from feedstocks and high-temperature heat compared to other sectors. We conclude that decarbonizing industry is technically possible, even though technical and economical hurdles arise. We also identify the drivers of costs associated with decarbonization and the impact it will have on the broader energy system.

The industrial sector is both a global economic powerhouse and a major emitter of GHG emissions

The industrial sector is a vital source of wealth, prosperity, and social value on a global scale. Industrial companies produce about one-quarter of global GDP and employment and make materials and goods that are integral to our daily lives, such as fertilizer to feed the growing global population, steel and plastics for the cars we drive, and cement for the buildings we live and work in.

In 2014, direct GHG emissions from industrial processes and indirect GHG emissions from generating the electricity used in the industry made up ~15 Gton CO2e (~28 percent) of global GHG emissions. CO2 comprises over 90 percent of direct and indirect GHG emissions from industrial processes. Between 1990 and 2014, GHG emissions from the industrial sector increased by 69 percent (2.2 percent per year)[1], while emissions from other sectors such as power, transport, and buildings increased by 23 percent (0.9 percent per year).[2]

Almost 45 percent of industry’s CO2 emissions result from the manufacturing of cement (3 Gton CO2), steel (2.9 Gton CO2), ammonia (0.5 Gton CO2), and ethylene (0.2 Gton CO2)—the four sectors that are the focus of this report. In these four production processes, about 45 percent of CO2 emissions come from feedstocks, which are the raw materials that companies process into industrial products (for example, limestone in cement production and natural gas in ammonia production). Another 35 percent of CO2 emissions come from burning fuel to generate high-temperature heat. The remaining 20 percent of CO2 emissions are the result of other energy requirements: either the onsite burning of fossil fuels to produce medium- or low-temperature heat, and other uses on the industrial site (about 13 percent) or machine drive (about 7 percent) (see Exhibit 1).[3]

Exhibit 1: Why are the steel, cement, ammonia, and ethylene sectors hard to abate?

Why are the steel, cement, ammonia, and ethylene sectors hard to abate?

Source: IEA data from World Energy Statistics © OECD/IEA 2017 IEA Publishing; Enerdata: global energy and CO2 data; expert interviews

After breakthroughs in the power, transport, and buildings sectors, industrial decarbonization is the next frontier

Global efforts have driven innovation and the scaling up of decarbonization technologies for the power, buildings, and transport sectors. This has led to major reductions in the costs of these technologies. Examples are the recent reductions in the costs of solar photovoltaic modules and electric vehicles. Less innovation and cost reduction have taken place for industrial decarbonization technologies. This makes the pathways for reducing industrial CO2emissions less clear than they are for other sectors.

Besides that, CO2 emissions in the four focus sectors are hard to abate for four technical reasons. First, the 45 percent of CO2 emissions that result from feedstocks cannot be abated by a change in fuels, only by changes to processes. Second, 35 percent of emissions come from burning fossil fuels to generate high-temperature heat (in the focus sectors, process temperatures can reach 700 °C to over 1,600 °C). Abating these emissions by switching to alternative fuels such as zero-carbon electricity would be difficult because this would require significant changes to the furnace design. Third, industrial processes are highly integrated, so any change to one part of a process must be accompanied by changes to other parts of that process. Finally, production facilities have long lifetimes, typically exceeding 50 years (with regular maintenance). Changing processes at existing sites requires costly rebuilds or retrofits.

Economic factors add to the challenge. Cement, steel, ammonia, and ethylene are commodity products for which cost is the decisive consideration in purchasing decisions. With the exception of cement, these products are traded globally. Generally, across all four sectors, externalities are not priced in and the willingness to pay more for a sustainable or decarbonized product is not yet there. Therefore, companies that increase their production costs by adopting low-carbon processes and technologies will find themselves at an economic disadvantage to industrial producers that do not.

Industrial companies can reduce CO2 emissions in various ways, with the optimum local mix depending on the availability of biomass, carbon-storage capacity and low-cost zero-carbon electricity and hydrogen, as well as projection changes in production capacity

A combination of decarbonization technologies could bring industry emissions close to zero: demand-side measures, energy efficiency improvements, electrification of heat, using hydrogen (made with zero-carbon electricity) as feedstock or fuel, using biomass as feedstock or fuel, carbon capture and storage (CCS), and other innovations.[4]

The optimum mix of decarbonization options depends greatly on local factors. The most important factors are access to low-cost zero-carbon electricity and access to a suitable kind of sustainably produced biomass because most processes in the focus sectors have significant energy- and energy-carrier-related feedstock requirements that could be replaced by one or both of these alternatives. The local availability of carbon storage capacity and public and regulatory support for carbon storage determine whether CCS is an option. The regional growth outlook for the four focus sectors matters, too, because certain decarbonization options are cost-effective for use at existing (brownfield) industrial facilities while others are more economical for newly built (greenfield) facilities.

Since the optimum combination of decarbonization options will vary greatly from one facility to the next, companies will need to evaluate their options on a site-specific basis. To help industrial companies narrow down their options and focus on the most promising ones, we offer the following observations, which account for current commodity prices and technologies (see Exhibit 2):

    • Energy efficiency improvements can reduce carbon emissions competitively, but cannot lead to deep decarbonization on their own. Energy efficiency improvements that lower fuel consumption by 15 to 20 percent can be economical in the long run. However, depending on the payback times on energy efficiency required by companies (sometimes less than two years), implementation can be less than the potential of 15 to 20 percent.

    • Where carbon-storage sites are available, CCS is the lowest-cost decarbonization option at current commodity prices. However, CCS is not necessarily a straightforward option for decarbonization. CCS imposes an additional operational cost on industrial companies, whereas further innovation could make alternative decarbonization options (for example, electrification of heat) cost competitive vis-à-vis conventional production technology. CCS can only be implemented in regions with adequate carbon-storage locations, and supportive local regulations and public opinion. CCS has the distinction of being the only technology that can currently fully abate process-related CO2 emissions from cement production.[5]

    • At zero-carbon electricity prices below ~USD 50/MWh, using zero-carbon electricity[6] for heat or using hydrogen based on zero-carbon electricity becomes more economical than CCS. Electricity prices below USD 50/MWh have already been achieved locally (e.g., hydro and nuclear-based power-system of Sweden) and could be achieved in more places with the current downward cost trend in renewable electricity generation. The minimum price that makes it less expensive to switch to zero-carbon electricity than to apply CCS for decarbonization depends strongly on the sector, local fossil fuel and other commodity prices and the state of the production site.

» At electricity prices below ~USD50/MWh, electrifying heat production at greenfield cement plants is more cost-competitive than applying CCS to the emissions from fuel consumption, provided that very-high-temperature electric furnaces are available.[7, 8]

» At electricity prices below ~USD35/MWh, hydrogen use for greenfield ammonia and steel production sites is more cost-competitive than applying CCS to conventional production processes.

» At electricity prices below ~USD25/MWh, electrification of heat in greenfield ethylene production and in brownfield cement production and usage of hydrogen for brownfield steel production are more cost-competitive than applying CCS to conventional production processes.

» Finally, below an electricity price of ~USD15/MWh, usage of hydrogen for brownfield ammonia production and electrification of heat for ethylene production are more cost-competitive than applying CCS to conventional production processes. This means that electric heat production and usage of electricity to make hydrogen are more economical approaches to decarbonization than CCS in all four focus sectors at this electricity price level.

Exhibit 2: With low electricity prices, cost-based trade-offs will favor more electrification and hydrogen than CCS

With low electricity prices, cost-based trade-offs will favor more electrification and hydrogen than CCS

Lower costs for capital equipment or process innovations could make electrification or the use of zero-carbon electricity based hydrogen economical at higher electricity prices.

    • Using biomass as a fuel or feedstock is financially more attractive than the electrification of heat or the use of hydrogen in cement production and at electricity prices above ~USD 20/MWh in steel production. Mature technologies are available for using biomass as fuel and feedstock in steel and as fuel in cement production. These technologies reduce emissions more economically than CCS on the conventional process. Biomass can also replace fossil fuel feedstocks for ethylene and ammonia production. Though this approach costs more than electrification or hydrogen usage, it also abates emissions in both the process and at end-of-life of the product, such as the emissions from incineration of plastics made from ethylene. The global supply of sustainably produced biomass, however, is deemed limited at the global level. Additionally, re-forestation to generate offsets might be a counter use of biomass rather than the shipping and usage in industrial processes.

    1. Demand-side measures are effective for decarbonization but were not a focus of this report. Replacing conventional industrial products with lower-emission alternatives (e.g., replacement of cement with wood for construction) would result in significant reductions in CO2 emissions from the four focus sectors. Radical changes in consumption patterns driven by technology changes could further offset demand, such as reduced build-out of roads (and therefore cement) through autonomous driving, reduced demand for ammonia through precision agriculture. Moreover increasing the circularity of products, by e.g., recycling or reusing them can also cut CO2 emissions. Producing material based on recycled products generally consumes less energy and feedstock than the production of virgin materials. As an example, producing steel from steel scrap requires only about a quarter of the energy required to produce virgin steel.

Industrial decarbonization will require increased investment in industrial sites and has to go hand in hand with an accelerated build-out of zero-carbon electricity generation

  • Completely decarbonizing the energy-intensive industrial processes in the four focus sectors will have a major impact on the energy system. It is estimated that it would require ~25 EJ to 55 EJ per year of low-cost zero-carbon electricity. In a business-as-usual world, only 6 EJ per year would be needed, indicating that, regardless of the mix of decarbonization options chosen, electricity consumption will go up significantly. The transition in the power and industrial sectors should thus go hand in hand. The industrial sector might be able to lower the costs of the power sector transition, e.g., by providing grid balancing, while being a large off-taker that can support increased build-out of generation capacity.

  • The total costs of fully decarbonizing these four sectors globally are estimated to be ~USD 21 trillion between today and 2050. This can be lowered to ~USD 11 trillion if zero-carbon electricity prices come down further compared to fossil fuel prices (see Exhibit 3).[9] These estimates are based on cost assumptions that do not allow for process innovations or significant reductions in the costs of capital equipment. Furthermore, they heavily depend on the emission reduction target, local commodity prices, the selected mix of decarbonization options, and the current state of the production site. The estimated costs for complete decarbonization of the four focus sectors are equivalent to a yearly cost of ~0.4 to 0.8 percent of global GDP (USD 78 trillion). According to the estimations in this report, about 50 to 60 percent of these costs consist of operating expenses and the remainder consists of capital expenditures, mainly for cement decarbonization.

An analysis of the effects of different electricity prices suggests that decarbonization would have an upward impact on the costs of the industrial products: cement doubling in price, ethylene seeing a price increase of ~40 to 50 percent, and steel and ammonia experiencing a ~5 to 35 percent increase in price.[10]

Exhibit 3: The total costs of decarbonization are highly dependent on the electricity price

The total costs of decarbonization are highly dependent on the electricity price

Source: McKinsey Energy Insights

Advance planning and timely action could drive technological maturation, lower the cost of industrial decarbonization and ensure the industry energy transition advances in parallel with required changes in energy supply

    • Governments can develop roadmaps for industrial decarbonization on local and regional levels. Setting such a longer-term direction for decarbonization could support planning for decarbonization by other parties, including industrial companies, utilities and owners of key infrastructure (such as the electricity grid or hydrogen pipelines), and unlock investments with long payback times. Such a roadmap should take a perspective, e.g., on the production outlook, resource availability (including carbon-storage sites), additional resources required (zero-carbon electricity generation, etc.), coordinated roll-out of infrastructure and demand-side measures, as well as the role government would play (e.g., in the development of critical infrastructure).

    • Adjust regulation and incentives in line with decarbonization roadmaps. Various policy mechanisms could support industrial decarbonization. These might include direct incentives for companies to decarbonize or adjustments to the financial requirements placed on utilities and other companies involved in energy generation and distribution.

    • Industrial companies should prepare for decarbonization by conducting a detailed review of each facility in their portfolio. Such a review should include the availability of low-cost zero-carbon electricity, zero-carbon hydrogen, biomass, and carbon-storage capacity near the facility as these will differ on a country-by-country basis. Interaction with other stakeholders, such as governments, utilities, and other industrial companies, could help to identify synergies between industrial decarbonization and decarbonization in other sectors or companies, driving targeted innovation and driving down costs. For example, companies in an industrial cluster might benefit from shared carbon-storage infrastructure.

    • Governments, industrial companies, and research institutions can support innovation and the scale-up of promising decarbonization technologies, which is required to reach full decarbonization of the industrial sector. Innovative decarbonization technologies could potentially lower the costs of the industry transition. Governments can support the development of innovative decarbonization options, including the scale-up of global markets, e.g., in certain types of biomass, or the introduction of innovative processes to lower implementation costs. Overall, decarbonizing industrial sectors requires collaboration across governments, industrial players, and research institutes, similar to the effort that led to the cost reduction and scale-up of renewable energy generation.

McKinsey & Company, www.mckinsey.com. Copyright (c) 2018 McKinsey & Company. All rights reserved. Reprinted by permission.

About the authors


Occo Roelofsen is a Senior Partner, Arnout de Pee is a Partner, Eveline Speelman is an Associate Partner, and Maaike Witteveen is an Engagement Manager in McKinsey’s Amsterdam office. Dickon Pinner is a Senior Partner in McKinsey’s San Francisco office and Ken Somers is a Partner in McKinsey’s Antwerp office.

References


[1] Feedstocks are the raw materials that companies process into industrial products. High-temperature heat is defined in this report as a temperature requirement above 500 °C.

[2] Based on IEA data from the World Emissions Database © OECD/IEA 2018, IEA Publishing; modified by McKinsey.

[3] Breakdown of emissions is defined by the use of various reports and datasets, most importantly IEA, Enerdata, heat and cooling demand, market perspective (JRC 2012), and sector energy consumption flow charts by the US Department of Energy combined with input from experts. Activities up and down the value chain are not included in these numbers and could lead to additional emissions, e.g., transportation of fuel to the production site or incineration of ethylene-based plastics at end of product life.

[4] Other innovations can be non-fossil-fuel feedstock change (e.g., alternatives for limestone feedstock in cement production) and other innovative processes (e.g., reduction of iron ore with electrolysis).

[5] At the current state of technology, process emissions from cement production can only be abated by a change in the feedstock. Alternatives for the conventional feedstock (limestone) are not available (yet) at scale. Hence, decarbonizing cement production currently relies on CCS.

[6] The zero-carbon electricity price should be the average wholesale industrial end user price, so including, e.g., transmission, distribution, and storage costs.

[7] Electrification of very-high-temperature heat (>1,600 °C) required in cement production would require research, as these temperatures are not yet reached in electric furnaces.

[8] Process emissions from cement production cannot be abated by a fuel change and therefore require CCS, irrespective of electricity prices.

[9] These total costs include all capital and operational costs on industrial sites, but exclude other costs, e.g., build-out of zero-carbon electricity generation capacity.

[10] Conventional prices assumed are: cement USD 120/ton, steel USD 700/ton, ammonia USD 300/ton and ethylene USD 1,000/ton.

Video

Schlumberger tests new technologies to find oil and gas methane leaks

Increased awareness of methane’s impact on the environment is leading to increased monitoring for methane leaks. In order to reduce the amount of methane emitted into the atmosphere, we need better detection technologies. Last summer, EDF collaborated with the world’s largest oilfield service company – Schlumberger – to test a variety of stationary and hand-held technologies to detect methane leaks from equipment in the upstream oil and gas sector. To learn more about how technology and innovation can help solve the methane problem visit business.edf.org.

Published on Mar 29, 2018

YouTube

Repsol and Google Cloud to optimize refinery management using big data and artificial intelligence

  • Repsol’s goal is to maximize the performance and efficiency of a refinery, which is among the largest and most complex industrial facilities.

  • Google Cloud will provide its computing power, experience with big data and machine learning expertise.

  • The initiative is part of Repsol’s commitment to digitalization, innovation and technology across all of its business areas.

Repsol has today announced that it is working with Google Cloud to launch a project that will use big data and artificial intelligence to optimize management of the Tarragona refinery. Refineries are among the largest and most complex industrial facilities.

Repsol’s Executive Managing Director of Downstream, María Victoria Zingoni, and Google’s Country Manager for Spain and Portugal, Fuencisla Clemares, participated in the launch of the project, which will be carried out in the Tarragona Industrial Complex and marks a pioneering challenge in the global refining industry.

This initiative puts the latest cloud technology from Google at the service of the refinery’s operators. Repsol’s objectives are to maximize efficiency, both in energy consumption as well as consumption of other resources, and to improve the performance of the refinery’s overall operations.

To achieve this, Google will make available to Repsol its data and analytics products, the experience of its professional services consultants and its machine learning managed service, Google Cloud ML, which will help Repsol’s developers to build and bring machine learning models to production in their refinery environment.

The management of a refinery involves around 400 variables, which demands a high level of computational capacity and a vast amount of data control. This is an unprecedented challenge in the refining world.

Until now, the highest number of functions integrated digitally in an industrial plant is around 30 variables, demonstrating the vast challenge this project presents. It aims to increase the number of variables being managed by more than 10 times. Repsol chose the Tarragona refinery to develop this initiative because the online configuration of its production schematics facilitates testing and implementation.

This project, as well as the collaboration with Google Cloud, is part of Repsol’s ongoing digitalization, innovation and technology projects development in all of its business units to improve its competitiveness and efficiency.

The project has the potential to add 30 cents on the dollar to Repsol’s refined barrel margin, which could translate to 20 million dollars annually for the Tarragona refinery, with significant upward growth if all optimization objectives are achieved.

Improvement of industrial processes

For Maria Victoria Zingoni “this is an efficiency project in all senses: it seeks to consume fewer resources; reduce energy consumption, which is the highest cost of a refinery; increase the unit reliability and, by extension, improve economic performance.”

“This initiative belongs to a more comprehensive plan to take advantage of the possibilities afforded us by the latest in technology, and improve industrial processes. We are not afraid of aiming for the stars, even if some projects will fail. This is about learning as fast as possible and that machines help people in their work,” said Repsol’s Executive Managing Director of Downstream.

Google’s Country Manager for Spain and Portugal, said that “This project demonstrates the commitment from Spanish companies to digital transformation and the application of machine learning in industrial processes, of which Repsol is a pioneer.

“At Google, we are deeply committed to sustainability and ensuring that we have a positive impact on the environment – and we see technology such as machine learning and data analytics play an important role in helping our customers maximize their own efficiency. We are proud to collaborate with a company such as Repsol, which has been a leader for many years in leveraging technological innovation to reduce its environmental impact,” said Fuencisla Clemares, Country Manager Google España y Portugal.

This project, as well as the collaboration with a partner like Google, is part of Repsol’s ongoing digitalization, innovation and technology projects development in all of its business units to improve its competitiveness and efficiency.

This project is compatible with other digital initiatives that are already in use at Repsol’s industrial facilities, such as Siclos, with which Repsol’s refinery control panel operators learn, in real time, the economic implications of operating decisions; or Nepxus, which increases planning, analysis and agility in decision-making in the control rooms of these industrial installations.

Tarragona is one of the six refineries that Repsol operates in Spain and Peru. This plant has the capacity to distill 186,000 barrels of oil a day and is Repsol’s third-largest unit.

The facility occupies over 500 hectares and is as large as the Tarragona’s city center. The refining unit processes 9.5 million tons of raw material a year and the storage tanks can hold a million cubic meters.

REPSOL Press Release 

Video

MOTIVE™ Directional Drilling Bit Guidance System

The MOTIVE™ Bit Guidance System is a decision automation tool that has proven to significantly improve drilling performance. This automated system works in real-time to balance different objectives when making steering decisions. The system takes into account each decision’s impact on drilling speed, tortuosity, and future production potential. The patented system considers rotary tendencies, motor yield, motor potential, the skill of the driller, geosteering adjustments, nearby wells, lease lines, geology, and directional drilling limits set by each operator.

www.motivedrilling.com

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Our fresh commitment to low carbon

The world is demanding more energy every day to support growth and prosperity. At the same time, it’s demanding energy with fewer emissions. At BP we’re taking on this dual challenge across all of our business activities. We’re growing our business, providing more energy to the world. And at the same time, we’re reducing emissions in our operations, improving our products and creating low carbon businesses. This is how BP is helping the world transition to a low carbon future. As part of this, we are setting some new and important targets. Head to bp.com/energytransition for details.

Published by BP on Apr 16, 2018

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Video

Inspiring engineers of the future

Shell is a passionate supporter of science, technology, engineering and mathematics (STEM) education. The skills of scientists, engineers, educators and leaders are essential to meeting the world’s demand for energy, whilst reducing carbon emissions. Our vision is to help equip future generations of problem-solvers, leaders and innovators to tackle the energy challenges that face us all. #makethefuture To find out more about STEM and the education programmes Shell support globally please visit http://www.shell.com/education Transcript: http://www.shell.com/content/dam/roya…

Together we can #makethefuture Visit our Website: http://www.shell.com/ Like us on Facebook: https://www.facebook.com/Shell/ Follow us on Instagram: https://www.instagram.com/shell/ Follow us on Twitter: https://twitter.com/shell Look us up on Flickr: http://www.flickr.com/photos/royaldut…

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Robo-Glove – Wearable technology that reduces the force needed to operate tools

Researchers at the NASA Johnson Space Center (JSC) in collaboration with General Motors (GM) have designed and developed Robo-Glove, a wearable human grasp assist device, to help reduce the grasping force needed by an individual to operate tools for an extended time or when performing tasks having repetitive motion. Robo-Glove has the potential to help workers, such as construction workers, hazardous material workers, or assembly line operators, whose job requires continuous grasping and ungrasping motion. The Robo-Glove also has potential applications in prosthetic devices, rehabilitation aids, and people with impaired or limited arm and hand muscle strength. This NASA Technology is available for your company to license and develop into a commercial product. NASA does not manufacture products for commercial sale.

Benefits

  • Wearable assist technology: a lightweight robotic glove that fits on your hand

  • Small and compact design

  • Human-safe robotics: pressure sensors give a sense of touch or haptic feedback

  • Self-contained glove: actuators, pressure sensors, and synthetic tendons are embedded

  • Ergonomic – the system helps reduce muscle strain from repetitive motion tasks

Applications

  • Construction

  • Hazardous material handling

  • Medical

  • Automotive Repair

  • Manufacturing

  • Repetitive motion work

  • Oil and gas exploration

The Technology

This technology is directed to the field of wearable robotics, where a machine's strength and a human's ability to see, feel, and think are combined to develop a more robust system than if each operates separately.
This technology is directed to the field of wearable robotics, where a machine’s strength and a human’s ability to see, feel, and think are combined to develop a more robust system than if each operates separately.

Originally developed by NASA and GM, the Robo-Glove technology was a spinoff of the Robonaut 2 (R2), the first humanoid robot in space. This wearable device allows the user to tightly grip tools and other items for longer periods of time without experiencing muscle discomfort or strain. An astronaut working in a pressurized suit outside the space station or an assembly operator in a factory might need to use 15 to 20 lbs of force to hold a tool during an operation. Use of the Robo-Glove, however, would potentially reduce the applied force to only 5 to 10 lbs.

The Robo-Glove is a self-contained unit, essentially a robot on your hand, with actuators embedded into the glove that provide grasping support to human fingers. The pressure sensors, similar to the sensors that give R2 its sense of touch, are incorporated into the fingertips of the glove to detect when the user is grasping an object. When the user grasps the object, the synthetic tendons automatically retract, pulling the fingers into a gripping position and holding them there until the sensor is released by releasing the object. The current prototype weighs around two pounds, including control electronics and a small display for programming and diagnostics. A lithium-ion battery, such as one for power tools, is used to power the system and is worn separately on the belt.

Johnson Space Center
2101 NASA Parkway
Houston, TX 77058

281.483.3809
[email protected]

OFFSHORE DECOMMISSIONING IN ASIA PACIFIC REGION: WHY ‘RIG TO REEF’ IS VITAL

The Asia Pacific region is set to follow the North Sea in increasing its decommissioning activity over the next decade. Indonesia, Brunei, Malaysia and the rest of the region is home to 833 installations that are on or over 20 years old – the average life expectancy of offshore assets. But with so much of the region’s infrastructure under threat from decommissioning, many have questioned the impact to the environment.

A thought piece by the National University of Singapore (NUS) singled out the importance of rig to reef in this context back in 2012. In this blog, we explore what could be done in the region to both keep the integrity of the sea bed and complete decommissioning applications as efficiently as possible.

RIG-TO-REEF

Rig-to-reef (RTR) is the practice of converting decommissioned platform infrastructure into artificial reefs for the seabed. The practice has already proved popular in the Asia Pacific when the storm-damaged Baram-8 in Malaysia was made into an artificial reef. Despite there being no current RTRs in place in the region, there is sure to be an appetite as decommissioning work increases.

Rigs prove popular with sea life, especially as they become an integral part of the seabed over their 20-30 year life span. An OCS report that focussed on the Gulf of Mexico in 2000 stated that fish densities were 20-50 times higher around the platforms than anywhere else in open water – a true sign that artificial reefs work.

PROS OUTWEIGH THE CONS

While operators may look towards asset life extension techniques to keep relevant rigs operating, those who are set to decommission will be pleased to know that the pros outweigh the cons in terms of implementing RTRs with old assets.

Despite potential navigational issues around the Asia Pacific region, operators creating RTRs could benefit from being more environmentally friendly, increasing fisheries in the field, and potentially negating costs such as rig disposal. The question on whether RTRs would be welcome in the region are so far undecided and confusing by governing bodies, according to the NUS.

GIVEN THE GREEN LIGHT

In her presentation for the National University of Singapore, Youna Lyons highlighted the large discrepancy between governing bodies and law in the Asia Pacific region that meant operators looking to RTRs would be left confused as to whether they could undertake a project after decommissioning.

“(While) international law does not prevent the re-use of rigs as artificial reefs, provided that it does not compromise the safety of navigation, IMO guidelines (on the matter) are inadequate. A paradigm shift is needed in the approach.”

The biggest issue seems to be the safety of navigation around such artificial reefs by shipping traffic. That aside, the law states that rigs can be re-used, it is just a case of where they will be able to be positioned.

RIG TO REEF IS VITAL

In summary, the presentation reveals how vital rig to reefs can be for both operators and environment. While operators can potentially save money, and enhance the environment they’ve extracted from, the seabed and sea life can see drastic increases in activity if the manmade reefs are positioned well – as long as governing bodies and local authorities agree, Asia Pacific could benefit from more RTRs in the future.

THE INCREASE OF DECOMMISSIONING

As operators around the world review their aged assets, in the current climate it is no surprise to see decommissioning projects beginning on non-profitable rigs. In the Claxton Engineering Decommissioning Case Study Pack, you will learn how the Claxton team have already helped operators on their decommissioning projects and helped to save time and money too.

To find out more about the free offshore Decommissioning Case Study Pack, and to get your hands on a copy, click here.

Please be sure to follow and subscribe to Claxton at http://insights.claxtonengineering.com/.

Originally written and posted by Andy Norman, Head of Brand and Marketing, Claxton.

 

Siemens’ BlueVault™ energy storage solutions bring clean, reliable power to offshore operations

A clean, reliable power supply is critical for offshore oil and gas assets.

Siemens is now applying its extensive electrification experience in the marine industry to offshore oil and gas, with a focus on reducing emissions and risk in particularly unforgiving operational environments. The company’s advanced lithium-ion battery-based solution, known as BlueVault™, is suited for both all-electric and hybrid energy-storage applications. BlueVault energy storage solutions are designed to help ensure continuity of power and to minimize carbon dioxide emissions, with an end goal of a low-emissions platform. The battery is designed to maximize life, performance and safety.

Since 2013, Siemens has been supplying the marine industry with an innovative Diesel-Electric Propulsion (DEP) system, BlueDrive PlusC, designed to reduce greenhouse gas emissions, fuel consumption and maintenance costs when compared to traditional diesel-electric propulsion systems.

The company already has a track record of developing cost- and emission-reducing solutions for marine applications. In 2015, Siemens jointly developed the world’s first electric car ferry, Ampere, with Fjellstrand shipyard and ship-owner, Norled. Today, the Ampere ferry’s zero-emission propulsion solution has no direct or indirect emissions, because the batteries are recharged using hydro-electric power. The all-electric ferry weighs approximately half that of a regular car ferry due to the aluminum hull, and uses only 150 kWh of renewable energy per crossing which eliminates emissions and reduces fuel costs by 60 percent.

Pursuant to its research and development efforts and experience with harsh offshore operating environments, the company will open a fully robotized and digitalized plant in Norway that will develop and manufacture energy storage technologies for both marine and offshore oil and gas applications. The same battery storage solutions for marine and offshore environments are also applicable to offshore wind farms. In the longer term, Siemens hopes to leverage its expertise to develop a low-emissions offshore platform.

“Energy storage solutions provide a means to establish a stable, reliable electrical network by buffering intermittency and providing clean, dispatchable power,” said Terje Krogh, CEO of Siemens Offshore Solutions. “The Ampere ferry, which is entirely emission-free, serves as an example of how an energy storage system could also be successfully applied in an oil and gas environment.”

Siemens has already signed several contracts for its new energy storage system and expects to deliver the first one this summer.

This press release and press picture are available at www.siemens.com/press/PR2018050165PGEN

For further information on energy storage solutions, please see: https://www.energy.siemens.com/us/en/renewable-energy/distributed-and-hybrid-power/energy-storage-solutions.htm

Contact for journalists
Janet Ofano
Phone: +1 803-389-6753; E-mail: [email protected]

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Johan Sverdrup – the digital flagship

Digital technologies are shaping the world around us, and Statoil intends to be a driver of change in the energy industry. This film provides an overview of the digital ambitions and technologies which Statoil is working to implement on the Johan Sverdrup field to further improve safety, production and value.

Published on Feb 8, 2018

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OTC 2018 – ION commences new 2D multi-client program offshore West Africa

HOUSTON, May 2, 2018 /PRNewswire/ — ION Geophysical Corporation (NYSE: IO) today announced acquisition began on a new 2D multi-client program offshore Ghana in partnership with Geoex and Ghana Geophysical. 

ION and its partners will acquire up to 7,200 km of data in advance of the license round anticipated in late 2018 to help refine understanding of the hydrocarbon potential of the area.  Similar to other ION BasinSPAN™ programs, West Equatorial AfricaSPAN was custom designed in collaboration with regional experts and clients to answer remaining geological questions with a survey tied to recent discoveries.  This data will be the first offshore Ghana to image 40 km below the seafloor.  In addition, ION’s Marlin™ operations optimization software will help maximize the safety and efficiency of the survey.  Acquisition is expected to be completed at the end of May 2018 with Fast Track products available in Q3 2018 and final imaging products expected in Q1 2019.

Ghana is believed to have up to 5-7 billion barrels of petroleum and up to 6 trillion cubic feet of natural gas in reserves and has renewed interest due to new projects coming online and the resolution of the maritime boundary dispute with Côte d’Ivoire in September 2017.  The Ghanaian Government is transitioning from an open door system to its first competitive bid round due to the petroleum legislation passed in August 2016 making its petroleum resource management more transparent.

“We are excited to support the Ghanaian government as the country prepares for its next offshore license round with the stated goal to attract additional investment to develop their reserves,” said Joe Gagliardi, Senior Vice President of ION’s E&P Business Development group.  “The new data we are acquiring will help a number of E&P companies properly evaluate the offshore acreage in advance of the country’s first competitive bid round later this year.”

To learn more, visit iongeo.com/WEASPAN.

About ION

ION develops and leverages innovative technologies, creating value through data capture, analysis and optimization to enhance critical decision-making, enabling superior returns.  For more information, visit iongeo.com.

Contacts

ION (Investor relations)

Executive Vice President and Chief Financial Officer
Steve Bate, +1 281.552.3011
[email protected]

ION (Media relations)

Vice President, Communications
Rachel White, +1 281.781.1168
[email protected]

Why millennials are snubbing jobs in the oil industry

Like many industries today, the oil industry is trying to sell its many job opportunities to the fastest growing portion of the global workforce: Millennials.

But unlike any other industry, oil and gas are facing more challenges in persuading the environmentally-conscious Millennials that oil is “cool”.

During the Super Bowl earlier this year, the American Petroleum Institute (API) launched an ad geared toward Millennials, who now make up the largest generation in the U.S. labor force.

“This ain’t your daddy’s oil”, the ad says, in what API described as “a modern look at how oil is integrated into products consumers use now and in the future supported by bold visuals.”

Despite its pitch to speak the Millennials’ language and reach out to the elusive generation, the ad sparked anger among many consumers and viewers.

Millennials continue to have the most negative opinion of the oil industry compared to all other industries, and they don’t see a career in oil and gas as their top choice of a workplace. The oil industry’s talent scouting and recruiting methods of the past are failing to reach Millennials, who want their work to have a positive impact on society, various studies and polls have found—a rather big ask for the oil industry.

This failure to reach the group that makes up the largest portion of today’s workforce—which now surpasses Generation X—points to a huge problem for the oil sector, as Baby Boomers move into retirement in droves.

Not only are Millennials snubbing oil and gas because of its negative image, they also seek different job perks than previous generations sought, and in this regard, the oil industry will need to do more as it becomes increasingly obvious that Millennials want different things than what oil executives think they want.

A total of 14 percent of Millennials say they would not want to work in the oil and gas industry because of its negative image—the highest percentage of any industry, McKinsey said in September 2016.

Young people see the industry as dirty, difficult, and dangerous, according to an EY survey published last month. EY’s survey polled Millennials—the 20-to-35-year-olds today—as well as Generation Z coming after them and found that younger generations “question the longevity of the industry as they view natural gas and oil as their parents’ fuels. Further, they primarily see the industry’s careers as unstable, blue-collar, difficult, dangerous and harmful to society.”

In addition, two out of three teens believe the oil and gas industry causes problems rather than solves them, the survey showed.

So ‘not your daddy’s oil’ is not sinking in with Millennials and Generation Z, and with many of them, it never will, despite the oil lobbies’ marketing efforts to try to make it sound like an attractive career path.

According to executives polled by EY, the top three drivers for young people would be salary (72 percent), opportunity to use the latest technology (43 percent), and a good work-life balance (38 percent). But young people—although they are also prioritizing salary—have other views on what they look for in a job. Salary is still the top priority at 56 percent, but a close second comes good work-life balance (49 percent), with job stability and on-the-job happiness equally important at 37 percent.

Executives are underestimating the importance of work-life balance and stability for Millennials while overestimating the allure of technology as a factor. It’s not surprising that Millennials are not as attracted to the opportunity to use new tech as oil executives believe they are – Millennials generally don’t see technology as a perk, they take it for granted.

Moreover, Millennials don’t see the oil and gas industry as innovative – a major driver of career choice among this generation. According to a recent report by Accenture, “Despite evidence to the contrary, many Millennials believe the sector is lacking innovation, agility, and creativity, as well as opportunities to engage in meaningful work. In fact, only 2 percent of U.S. college graduates consider the oil and gas industry their top choice for employment.”

Accenture is warning that ‘the talent well has run dry’ and said:

“We believe the growing workforce deficit will, in fact, be a greater barrier to oil and gas companies’ upturn success than any deficits that might exist in capital equipment or supplies.”

The oil and gas industry is losing the competition for talent recruitment to industries that are more appealing to Millennials, and U.S. oil and gas firms will face the talent crunch first, according to Accenture.

“Any mature industry has to think about the fact that there’s a new sheriff in town with new values, new spending habits,” Jeff Fromm, an expert in marketing to American Millennials, told Bloomberg.

And if the oil and gas industry wants to get this ‘new sheriff in town’ on board, it needs to profoundly change recruitment strategies and talent sourcing. But with the negative image that is probably set to become even more negative—despite oil organizations’ marketing efforts—oil and gas have a huge workforce problem looming.

Get the latest Oil WTI price here.

Read the original article on OilPrice.com. Copyright 2018.

OTC 2018 – RealWear Adds Scaling Capability Through New Industry Support

RealWear Signs Global Agreement with Honeywell to Connect Frontline Workers in Energy and Process Manufacturing Industries with Intrinsically Safe Devices

May 1, 2018 – HOUSTON (Offshore Technology Conference – OTC) – RealWear®, the global leader in ruggedized wearable computers for industrial customers, today announced that it has taken a big step forward and further validated the industrial wearable computing market.  RealWear signed a strategic agreement with Honeywell to co-brand and sell the RealWear HMT-1® and HMT-1Z1™ wearable computers and accessories globally. The HMT-1Z1 is the world’s first and only intrinsically safe head-worn wearable computer (ATEX Zone 1 and Class 1 Division 1) for the highly competitive industrial sector, including the energy and process manufacturing industries.

“The RealWear HMT-1Z1 head-mounted, wearable computer helps us to efficiently connect the worker to the information he or she needs in real time from anywhere.” – Youssef Mestari, Honeywell Connected Plant 

“With Skills Insight Intelligent Wearables, part of our Honeywell Connected Plant portfolio, we are focusing on how to make industrial workers safer and more productive when they are out in the field,” said Youssef Mestari, Program Director, Honeywell Connected Plant.  “The RealWear HMT-1Z1 head-mounted, wearable computer helps us to efficiently connect the worker to the information he or she needs in real time from anywhere.”

“With the level of strength from Fortune 100 players like Honeywell, we are well poised to get these intrinsically safe wearable computers quickly into the field to empower hands-free connected workers, wherever they go,” said Andy Lowery, Cofounder and CEO of RealWear.

Certified for ATEX Zone 1 use, the HMT-1Z1 is the only global intrinsically safe product on the market, meaning it presents no ignition risk where potentially explosive atmospheres exist during routine operation.

Certified for ATEX Zone 1 use, the HMT-1Z1 is the only global intrinsically safe product on the market, meaning it presents no ignition risk where potentially explosive atmospheres exist during routine operation.

“We’ve had good success onboarding and deploying HMT-1 units and are eagerly awaiting the HMT-1Z1™ units,” said Bryan Shackelford, an innovation representative at Eastman Chemical, Worldwide Engineering and Construction Services and Solutions. “Those intrinsic safety-rated units will serve to bridge workflow into hazard-rated areas where we’ve historically had difficulty deploying new technology. We hope to see a step change in operations with the deployment of the RealWear HMT-1Z1.”

In a recent Bloomberg-Business Week article, it was reported that one oil and gas company spent $50,000 in just travel to fly a specialized crew by helicopter to replace a critical turbine.  However, that cost is dwarfed by the lost revenue incurred during the arduous travel.  An average-sized refinery will lose $12 million per day due to an unplanned outage. These travel costs and the loss of revenue is avoidable with a connected worker strategy centered around the RealWear HMT-1Z1. A connected field worker can safely communicate with experts anywhere in the world, adding eyes and real-time information to a complicated operation at a refinery or on an oil platform. The device can help bring a heavy-duty machine back online in minutes or hours, not days, saving millions.

Certified for ATEX Zone 1 use, the HMT-1Z1 is the only global intrinsically safe product on the market, meaning it presents no ignition risk where potentially explosive atmospheres exist during routine operation. There are about 700 oil refineries globally with 250,000 users in North America alone who are currently using intrinsically safe two-way radios, mobile phones, and other devices that all require the use of workers’ hands, but who are better served with a voice-controlled ruggedized wearable computer.

ABI estimates energy and utility companies’ annual spend on AR headsets and related technology will reach $18 billion in 2022, among the most of any industry.

The RealWear HMT-1Z1™ can be purchased directly through Honeywell.

About RealWear

RealWear®, the global leader in hardware technology for industry, has built the first hands-free ruggedized head-mounted wearable computer for Connected Worker programs, the HMT-1. RealWear has more than 350 customers worldwide in oil and gas, utilities, automotive and manufacturing. Through its growing ecosystem of 75 software providers, RealWear offers remote mentor, document navigation, industrial IoT visualization and digital workflow solutions to reduce downtime, increase productivity and improve worker safety, eliminating the need for costly or dangerous repairs.

Media Contacts:

Aaron Cohen, Head of Communications
[email protected]
415-819-7791

www.realware.com

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Noble Corp. and GE Partner on World’s First Digital Rig

 

Noble Corporation, a leading offshore drilling contractor for the Oil and Gas industry, is partnering with GE on the world’s first digital drilling vessel as an innovative step forward to unlocking the potential of digital offshore marine operations. With the Digital Rig℠ solution, powered by Predix Platform, Noble is aiming to expand data-driven operations support, while gaining visibility into drilling inefficiencies. LEARN MORE ABOUT GE DIGITAL: https://www.ge.com/digital SUBSCRIBE TO THE GE DIGITAL CHANNEL: https://www.youtube.com/c/GEDigital?s… CONNECT WITH GE DIGITAL ONLINE: Visit GE Digital’s Website: https://www.ge.com/digital/ Follow GE Digital on Twitter: https://twitter.com/GE_Digital Find GE Digital on LinkedIn: https://www.linkedin.com/company/2681277

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Helping gas companies reduce their greenhouse emissions – Q&A

Over the next decade, oil and gas companies have a huge challenge and major responsibility to significantly reduce their carbon footprint and address climate change.

Ernesto Santibanez Borda, a PhD researcher in the Earth Sciences & Engineering Department at Imperial College is looking to help these companies choose the best method for limiting emissions associated with using and transporting natural gas. We interviewed him about his work with Professor Anna Korre.

1. What problem you are trying to solve/address in your PhD?

We recognize that hydrocarbon companies are faced with an enormous task to figure out how to reduce their emissions dramatically in a cost-effective and efficient way while providing energy for increased world consumption. While predictions from the International Energy Agency (IEA) outline gas consumption growth as the fastest among all fossil fuels resulting in a possible gas-carbon demand parity by 2040, there are still significant emissions from natural gas.

My PhD research focuses on the natural gas supply chain including the stages of production, processing, and transport through pipelines or as Liquefied Natural Gas (LNG). It is about developing an intelligent approach to choosing which technologies could be adopted to reduce greenhouse gas emissions (GHG) in a cost efficient way.

The idea is to also consider market conditions and policy related uncertainties to help strategic decision-making.

2. That sounds like a big project. So, what steps are involved in your PhD?

My PhD can be divided into three main parts.

First, I will use the Life Cycle Analysis (LCA) methodology to understand the full extent of greenhouse gas emissions in the natural gas supply chain. This involves assessing all environmental impacts associated with all the stages of the natural gas supply chain from extraction through to distribution.

I am using models developed by the MERG (Minerals, Energy and Environmental Engineering Research Group) at Imperial College but I will also develop new ways. These models differ from the majority available in the market as there is a greater degree of accuracy in the estimation, most of the emissions are calculated based on material balance principles (which means accounting for material entering and leaving a system), and engineering calculations.

The second part is establishing the costs associated with each technological path using the Life Cycle Costing (LCC) methodology. When companies try to estimate their emissions through LCA, they can often see ways to reduce their emissions by adopting specific technologies. But in order to be able to implement those changes it is important to cost all those options.

The final step is to determine the best combination of technologies and practices that minimise environmental impacts and costs in order to aid industry decision-making. We are doing this  through multi-objective optimisation which is a technique that models a problem mathematically and minimises or maximises mutually excluding objectives. In this case, we want to see how low the emissions can be, if we spend a specific amount of money.

3. Is your PhD part of a larger body of work at Imperial College? Who else are you working with?

Yes, I work within Department of Earth Science and Engineering in the MERG group underthe supervision of Professor Anna Korre and Dr. Zhenggang Nie.

The developed models are currently being tested in different case studies, some of them provided by the Oil and Gas Climate Initiative project in which we are involved in, and the results will be compared with the reported emissions/costs and benchmark values from literature to validate our results. We also want to analyse case studies from the Brazilian natural gas value chain.

I have also been working with the Sustainable Gas Institute, and using a lot of data from Dr Paul Balcombe’s paper (Methane & CO2 emissions from the natural gas supply chain).

4. Why are you concentrating on LNG?

Projections by IEA state that by 2040 inter-regional gas trade can expand by up to more than 40%, and LNG’s share of inter-regional gas trade can increase from 10 to 50%.

In addition, we believe that an optimisation assessment of the environmental impacts and costs of the LNG processes has still not been thoroughly addressed considering the impacts it has on other parts of the natural gas value chain.

5. What motivated you to work in energy research?

Energy is vital to the international economy, but there are still so many challenges; improving efficiency, and reducing our environmental impact as well as meeting increasing global demand.

I found the research around finding ways to meet global demand while making sure we keep to the environmental targets set by the latest international commitments quite fascinating. Seeing companies in the energy sector get involved also encouraged me to join this research area.

Finally, I like the work of integrating different knowledge disciplines such as hydrocarbon processing, operations research, and environmental assessment in order to produce a tool that could be used to make intelligent decisions that have a wide impact.

6. What attracted you or influenced you to becoming an engineer?

At secondary school, I realized I was interested in maths and science, so it was natural to start looking at careers that are related to those subjects, and engineering specifically caught my attention because it is practical and helps model, and find reasonable solutions for daily problems faced by individuals, companies or the society.

The fact that it does not just involve hard calculations, but can also integrate other disciplines into the decision-making also fascinated me because it opened a whole world of options on how to approach a specific problem.


Ernesto Santibanez Borda is a Brazilian and Chilean national. He holds a BSc Engineering from Pontificia Universidad Catolica de Chile, and MSc Petroleum Engineering from Imperial College London.

He also has 2 years of experience as production planning engineer in Escondida mine, operated by BHP Billiton (Chile)

By Zara Qadir

The Sustainable Gas Institute

Artificial Intelligence in Oil and Gas – Comparing the Applications of 5 Oil Giants

Today, AI is helping the oil and gas industry chart its future course. Since no previous sources have provided an in-depth look at the impact of AI among the leading oil and gas companies, we set out in this week’s research to help answer questions that oil and gas leaders are asking:

  • What types of AI are applications currently in use by leading oil and gas companies such as ExxonMobil and Shell?

  • What (if any) results have been reported on AI applications implemented by leading companies in the oil and gas industry?

  • Are there any common trends among their innovation efforts – and how could these trends affect the future of the oil and gas industry?

This article seeks to provide a comprehensive look at applications of AI by the five leading oil and gas companies. Our ranking of companies is based on the Forbes’ 2017 Global 2000 ranking of the world’s biggest public companies.

Through facts and figures we aim to provide pertinent insights for business leaders and professionals interested in how AI is impacting the petroleum industry.

Prior to exploring the applications, we’ll present the common patterns that emerged from our research in this industry.

Artificial Intelligence in Oil and Gas – Insights Up Front

The most popular AI applications from the top five industry leaders currently appear to be: 

  • Intelligent robots  – Robots designed with AI capabilities for hydrocarbon exploration and production, to improve productivity and cost-effectiveness while reducing worker risk (see ExxonMobil and Total below)

  • Virtual assistants – Online chat platform that helps customers navigate product databases and processes general inquiries using natural language (see Royal Dutch Shell below)

In the full article below, we’ll explore the AI applications of each company individually. We will begin with ExxonMobil, the #1 ranked company in this industry based on the Forbes’ 2017 Global 2000 ranking of the world’s biggest public companies.

ExxonMobil

Among its ongoing collaborative efforts with approximately 80 universities in the U.S. and abroad, In December 2016, ExxonMobil announced that it is working with MIT to design AI robots for ocean exploration. Brian Williams, an MIT professor and a designer of the AI software that helped create NASA’s Mars Curiosity Rover is a key member of the project team.

While the business advantage of using AI in deep-sea exploration may not be immediately apparent, the company aims to apply AI to boost its natural seep detection capabilities. Natural seeps occur when oil escapes from rock found in the ocean floor. An estimated 60 percent of oil underneath the earth’s surface in North America is due to natural seeps. Robots with the ability to navigate these oceanic regions and detect oil seeps can contribute to protecting the ecosystem and serve as indicators for robust energy resources. It is unclear specifically when ExxonMobil’s ocean exploring AI robots are expected to be deployed.

Oil Seeps

A visual depiction of natural oil seeps (source)

As a founding member of MIT’s Energy Initiative, ExxonMobil has committed a reported $25 million over 5 years to support energy research conducted by MIT faculty and staff. While the company has not published the total amount invested across its 80 university collaborations, we can gain some insight from the following published figures:

  • Princeton University: $5 million over 5 years

  • The University of Texas at Austin: $15 million

“Our goal is to have these submersibles embody the reasoning of the scientists that program them. You want the explorer to do the science without the scientist there. They need to be able to analyze data, keep themselves out of harm’s way and determine novel solutions in novel situations that go beyond basic mission programming. They need to have some common sense and the ability to learn from their mistakes.” – Professor Brian Williams, MIT

Exxon MIT AI

ExxonMobil’s MIT robotics collaboration (source)

Through its partnership with the MIT Energy Initiative and related efforts, ExxonMobil has made energy efficiency and the exploration of new energy sources a core focus of its business priorities. According to its 2016 annual report, the company has reportedly invested roughly $7 billion since the year 2000 on R&D and “deploying emissions-reducing technologies.” The company does not itemize allocations for these technologies and specifics on AI were not published.

Royal Dutch Shell

In August 2015, Shell announced that it would be the first company in the lubricants sector to launch an AI assistant for customers (an anomaly in terms of applications of artificial intelligence in oil and gas). Normally, customers searching for lubricants and related products must navigate a large database in order to find the ideal product(s) they are searching for. Shell aims to use its avatars, Emma and Ethan, to help customers discover products using natural language.

The Shell Virtual Assistant functions through an online chat platform through the company’s website. Examples of information that the system can provide include where lubricants are available for purchase, a range of available pack sizes and general information regarding the technical properties of specific products.

To provide context, the company claims that its Shell Virtual Assistant:

  • Handles over 100,000 data sheets for 3,000 products

  • Provides information on 18,000 different pack sizes

  • Understands 16,500 physical characteristics of lubricants

  • Matches Shell products to 10,000 competitive products

The Shell Virtual Assistant is only currently available in the U.S. and U.K. but also complements four other Shell services including Shell LubeMatch which reportedly provides “over two million product recommendations for Shell customers” annually and is accessible across 138 countries in 21 languages.

Shell Virtual Assistant

An infographic representing the claims made about Shell Virtual Assistant – from Shell’s website

We were able to access the virtual assistant on the company’s website. In a note to users posted above the platform, Shell states that the virtual assistant is still in pilot mode and that efforts are ongoing to increase the knowledge of the virtual assistants and to monitor their effectiveness.

At tech emergency, we have become increasingly wary of “chatbot” and “virtual assistant” efforts that present an innovative story without a substantive business application. It is difficult to assess the genuine business value of the Shell Virtual Assistant at this time, but we tend to air on the side of caution, and we encourage our business readers to do the same (we have collected a series of chatbots that do appear to be driving business value today, and we highlight them in our “7 chatbot use cases” article).

It behooves any company to present an exciting and innovative front in the press – and chatbots seem to be a “low hanging fruit” for supposed AI applications. This is by no means a warning that we specifically state for Shell – all press-facing technology initiatives serve the purpose of molding perceptions about the company (the goes for every industry). We do our best to dig for the genuine business ROI of AI applications, and we advise our readers to approach applications and press releases with skepticism, bearing in mind the motives of the companies behind them (which do not have to be malicious to be misleading and falsely optimistic).

Similar to Shell LubeMatch, the company is also looking to expand the service to other countries and languages.

Shell’s R&D expenditures in 2016 totalled $1.014 billion. While specifics on AI were not reported, according to its Investor’s Handbook, R&D priorities are focused on “improving the efficiency of its products, processes, and operations”, and there is a concentration on developing technologies which support low-carbon energy.

Subsea 7 Shell Robot

Shell’s innovation in collaboration with Subsea 7 has created an Autonomous Inspection Vehicle
that claims to provide safer and better inspections – at a significant cost savings

In the future, the company reportedly seeks to integrate AI and automation into its facilities. Shell envisions that automated robots will be able to take over routine observational tasks and data gathering currently conducted by human employees. The company reportedly integrated a virtual assistant called Amelia  into its business model to more efficiently respond to inquiries from suppliers regarding invoicing.

Shell believes the future of AI in its industry will see a significant increase in unmanned and automated facilities.

China Petroleum and Chemical Corp. (Sinopec)

Sinopec has hinted at the role of AI in moving innovation forward in the oil and gas industry. The company boasts a long-term plan to roll out construction of 10 intelligent plants with a goal of a 20 percent reduction in operation costs.

On the manufacturing front, Huawei (Chinese telecom company) in April 2017 announced a collaborative effort involving Sinopec to design what is described as a “smart manufacturing platform.”

The platform description highlights AI as one of 8 core capabilities of the platform which aims to deliver a centralized method of data management and support integration of data across multiple applications used to manage factory operations.

AI would serve to establish rules and models that would inform how data is interpreted and offer opportunities for identifying valuable insights to improve factory operations. Huawei did not specify a timeline for when Sinopec is expected to fully implement the platform.

Total

Hydrocarbon exploration, the ability to map and identify oil and natural gas deposits beneath the earth’s surface, is a growing area of focus in the oil and gas industry. However, more innovative and environmentally-friendly methods of achieving improved effectiveness and efficiency are needed in the field. Environmental conditions are increasingly challenging for workers conducting hydrocarbon exploration thus technology capable of handling the task while retaining optimal functionality is highly desirable.

In an effort to establish what is described as the “first autonomous surface robots able to operate on oil & gas sites,” Total launched an international competition in December 2013. Total’s ARGOS challenge (Autonomous Robot for Gas & Oil Sites) was narrowed down to five teams hailing from Europe, Asia and South America who were provided with a maximum of three years to finalize their prototypes. For each of the 5 teams, Total provided a maximum of €600,000 (approximately $707,376) to support research and design, and a single prize of €500, 000 (approximately $589,522.50) for the winning robot.

AI was a key component of how the robot would function. Total expected that competitors ensure that their robots were able to deliver reports encompassing real-time data collection related to inspection points (locations where exploration is taking place) and analyses around the effectiveness of the locations of interest.

Total established key goals for the ARGOS robot:

  • The ability to carry out inspections, during the day or night, which are currently performed by humans.

  • The ability to detect abnormal equipment activity and intervene in an emergency. Examples may include simple equipment malfunctions or more high-risk situations such as gas leaks.

In May 2017, Total selected ARGONAUTS designed by a team from Austria and Germany as its winner. Total retains exclusive intellectual rights to the technology behind the ARGONAUTS robot for a period of five years. No further announcements have been made as to when the company will begin implementing ARGONAUTS.

Within its Exploration and Production segment, Total reports that over half of R&D allocations are focused on improving exploration capabilities; hydrocarbons and robotics are specifically mentioned. Innovation and R&D expenditures for oil and gas activities totaled $689 million in 2016.

(Readers with a specific interest in robotics and vehicles for the heavy industry may want to listen to our heavy industry-focused interview with Dr. Sam Kherat on our AI in Industry podcast.)

Gazprom

In June 2017, Gazprom and Yandex (described as Russia’s leading internet company) entered into a cooperation agreement for the implementation of new projects in the oil and gas industry. The two companies plan to tap into AI and machine learning to roll out their prospective initiatives.

Specifically, the collaboration is expected to focus on:

  • Drilling and well completion

  • Modeling oil-refining strategies

  • Optimizing other technological processes

The cooperation agreement reportedly provides flexibility for independent exploration of technologies currently in use in the oil and gas industry and collaborative development and application of projects in R&D. Data sharing and technical support for employee training are also potential points of interest.

“Oil and gas are one of the most exciting industries currently since it involves massive volumes of data, and any easy solutions for optimizing production and business processes have long since been implemented. This combination, together with significant turnover and high level of technological development, creates good opportunities for securing a major effect from implementing solutions based on machine learning and artificial intelligence, and we look forward to a productive partnership, in the long term.” – Alexander Khaytin, COO, Yandex Data Factory

Time will tell specifically how Gazprom and Yandex will leverage AI and machine learning throughout their various initiatives as specific around implementation have not yet been reported.

Gazprom’s technology development plan appears to be deeply rooted in strategic partnerships. In fact, the company claims that it is taking an active approach to identifying innovative, collaborative opportunities that align with its strategic priorities.

Innovation has certainly been a feature of Gazprom’s media profile, however at this current time, our research provides inconclusive evidence of any AI applications that currently in progress or that have demonstrated some preliminary results.

Concluding Thoughts

Leaders in the oil and gas industry are integrating AI in multiple areas. Reducing the carbon footprint, deep sea exploration of hydrocarbons and the implementation of innovative, sustainable energy strategies are driving the pace of evolution in the field.

We suspect that the companies we researched for this article are also implementing lots of business intelligence AI applications – but that these technologies are less frequently mentioned in press (exciting robots and noble environmental efforts are better PR for oil giants than predictive analytics for fuel yields, for example). Nevertheless, we feel that the applications highlighted above should give business leaders a healthy overview of the current AI initiatives among the biggest players in the petroleum industry.

Global energy investment by sector took an interesting turn in 2016. For the first time,  the electricity sector pushed ahead of oil and gas sector. However, the oil and gas sector remains at two-fifths of the global energy supply investment.

AI robots are a promising area of interest particularly to help curb the risk of exposure to dangerous working conditions for many employees. While the U.S. has experienced a downward trend of labor-related injuries or fatalities in the field in recent years, efforts to improve employee working conditions are a smart investment. We predict that improvements in robotic dexterity in any field (retail, agriculture, manufacturing, etc) are likely to trickle directly to robots tasked with dangerous jobs such as those in oil and gas, and fire/rescue. We’ll be following the robotics field in the years ahead, and continuing to update our listings of innovative robotics vendors.

Among oil and gas companies (who are not generally seen to be AI innovators) we can expect industry leaders to be the early adopters. Big budgets and existing tech talent are necessary to implement robust AI initiatives (particularly for complex robotics programs), and few companies on earth have pockets as deep as the big oil giants. We suspect that relatively smaller oil and gas companies will mostly be following the AI leadership of the giants to currently rule the petrol realm.

Published  by Kumba Sennaar

Credit source: Tech Emergence 

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Produced Water Facility at Chevron San Ardo Oil Field Features the First-Ever Installation of OPUS®

SCOPE

Chevron’s San Ardo oil field in Southern California recovers more than 10,000 barrels of heavy oil each day. The oil extraction process generates large volumes of produced water that require treatment and management, typically disposed of by deep well injection. Chevron engaged Veolia’s water treatment technology, engineering and operations experts to provide a new solution for sustainably treating the produced water. This would allow Chevron to minimize its water impact, while maximizing efficiency and significantly expanding production.

Southern California Refinery Case Study

PDF – 2.12 MB

To achieve this, Veolia provided Engineer-Procure (EP) services and operates a produced water management facility at this oil field that features the first-ever installation of Veolia’s OPUS® (Optimized Pretreatment and Unique Separation) technology. In this case, Chevron San Ardo’s treated water is used in two ways – reused for steam generation, and released into aquifer recharge basins that replenish local water resources and allow Chevron to recover more oil. The reliable operations & maintenance of the plant is backed by a Veolia performance guarantee.

CHALLENGE

The process of extracting oil from the ground generates a volume of water that can range from 10 to 20 times the oil production rate. Historically, a portion of this water had been recycled and softened for reuse in steam generation, with the remainder going to local EPA class II injection wells for disposal. However the injection zone capacity is limited, which constrains full field development and daily production levels.

The raw produced water for this oil field is 200°F, and contains about 25 ppm free oil, 80 ppm TOC, 240 ppm silica, 26 ppm boron, 240 ppm hardness and 6,500 ppm Total Dissolved Solids (TDS). The project goal was to reduce the feed water TDS to less than 510 ppm and boron to less than 0.64 ppm for discharge, while achieving 75% water recovery across the treatment system and minimizing the volume of produced water requiring re-injection. For steam generation, the project goal was to reduce the feed water hardness to less than 2 ppm total hardness as CaCO3.

SOLUTION

Veolia provided Chevron with the first produced water facility in the world to use its OPUS® technology, a multiple-treatment process that removes contaminants sufficiently to meet the established requirements for discharge. The technology and services provided by Veolia enables the plant’s entire water cycle to be managed in a truly sustainable way, while simultaneously expanding oil production capacity.

Since the plant was commissioned in 2008, Veolia has operated and maintained (O&M) the facility for Chevron.  Under its O&M contract, Veolia provides operations for the plant, which treats a combined 150,000 barrels of produced water daily, and oversees the facility’s maintenance according to an established performance guarantee. Additionally, Veolia provides Chevron with on-site and off-site technical and engineering support to troubleshoot issues, maintain optimal operations, prevent failures and implement processes to help maximize oil production.

RESULT

Veolia’s innovative application of its OPUS® technology – groundbreaking for produced water management – has delivered exceptional value back to Chevron San Ardo. By developing a sustainable solution that allows up to 50,000 barrels per day of produced water for surface discharge and another 75,000 barrels per day for steam generation, Chevron is minimizing its environmental impact on water-stressed California by returning water to the aquifer recharge basins. And by avoiding deep well injection, Chevron has a long-term solution for managing produced water that limits its regulatory risk and supports expanded production activities.

Thanks to Veolia’s expert operations & maintenance staff who run the facility for Chevron, the produced water is consistently treated to levels that allow for surface discharge to replenish local water resources – a critically important factor for oil field operations and their social license to operate in California. With plant operations handled by Veolia and backed by a performance guarantee, Chevron can focus on its core operation of oil production.

By partnering with Veolia, Chevron San Ardo accomplished its objective of achieving a more circular, sustainable and reliable business operation.

McKinsey: Operating models for oil and gas fields of the future

As the global energy transition accelerates, upstream operators must modernize and shift to more economic operating models. Where and how should they seek the next generation of efficiency gains?

As predictions of an early peak in oil demand take hold, upstream operators must find ways to produce more energy, more efficiently. Many have made significant performance gains in recent years. Across the sector, production costs are down 30 percent; safety incident frequency has fallen by a third, and production losses have declined by 15 percent since 2014. Yet more is necessary.

A marked spread in performance remains between the bottom and top quartile operators in every basin. On the UK Continental Shelf (UKCS), for instance, over 40 percentage points separate the lowest production efficiency asset from the top quartile. Similarly, the highest cost asset on the UKCS has twice the unit operating cost as the median and four times that of the top quartile in the basin.1

Furthermore, new technologies and ways of working are resetting top quartile performance levels. Our research2shows digital technologies may improve total cash flows by USD 11 per barrel across the offshore oil and gas value chain, adding USD 300 billion a year by 2025.

What distinguishes the success cases from the also-rans? What sustains their improvement momentum? Through our extensive experience of leading asset turnarounds in Petroleum Asset eXcellence, we observe that upstream operators who sustain their improvement momentum do two things well.

First, they challenge five interlinked drivers of their operating model in an integrated way (Exhibit 1). These drivers are: their asset strategy; physical equipment-in-place; work required to operate and maintain that equipment; workflows and methods used to conduct that work; and the competencies required from the team deployed to do it. While each driver will yield some efficiency gains when used alone, in aggregate, they can more than double the value potential of existing operations.

Second, having had one go at improving their operating model, these operators are willing to build on what did not work in round one, and take a second, third, or even fourth look. In fact, they build a continually evolving operating model that achieves higher and more predictable production performance, operating costs for a ‘lower forever’ price environment, and smaller, flexible and more diverse teams that are better suited to the industry’s aging pool of skilled labor.

Exhibit 1
What do successful operators do well?

This article lays out a concrete logic that any operator might use to develop a continually evolving operating model and illustrates through real examples the success factors of making this change happen.

Developing a clean-slate vision of your operating model

In early 2015, an operator with upstream assets in various life stages found itself with negative cash flows, declining production and escalating costs. A vertiginous price drop and unconvincing track record of operational performance made any prospect of recovery seem unlikely. The operator went back to a clean slate: it took a hard look at its field and hub strategies—reprioritizing its efforts across near-field exploration, wells-reservoirs-facilities management and asset rejuvenation; made radical choices to optimize lifting costs and staffing levels; and pursued capital productivity relentlessly across its portfolio. Over the next year, as the operator’s competitiveness improved, its confidence rose as well.

It took another look at its operating model, replicating this end-to-end clean-slate approach, and emerged with an ambitious agenda to restore positive cash flows within two years. Since then, this operator has divested non-core assets, rezoned unwanted surplus capacity on declining assets, improved front-line agility, and embraced digital technologies. With a continually evolving operating model, it has reverted to positive cash flows a year earlier than planned, marking a first in its recent history.

How did the operator build a clean-slate vision of its operating model? What logic does it apply every year? Exhibit 2 highlights the five interlinked drivers of operating model redesign and provides a checklist of questions any operator might ask itself.

Exhibit 2

Leading upstream operators maintain a coninually evolving operating model.

1. How does your asset strategy fit with your asset’s life stage?

Exploration and production (E&P) companies rarely look at asset strategies in operational excellence programs. This is a missed opportunity. Clean-slate asset strategies help operators make deliberate choices on which fields to grow, operate as mature, swap with others, abandon, or divest. A Western European operator with mature operations realized that half the fields in its portfolio would generate 95 percent of its future cash flows. Consolidating the portfolio would free up scarce capital and talent for its most productive assets with material remaining reserves. Moreover, legacy ownership structures concealed bottlenecks in third-party infrastructure: this restricted current operating capacity and the ability to mature reserves through production. Redrawing portfolios in line with which operator-controlled critical processing capacity and evacuation routes—swapping assets and acreage with contiguous operators, for instance—could improve the basin’s future economics and simplify day-to-day operations for individual parties.

A regular discipline of considering clean-slate asset strategies—commonly in an annual cycle—helps revisit field development plans and improve recovery rates. An African client with a portfolio of 800 closed-in wells concluded that intervening in a mere 5 percent of the closed-in well stock could add 30 kboe/d in the first year, with payback also within the same period. It made wells and reservoir management a top priority in capital allocation and operational plans across its upstream portfolio.3

Would you like to learn more about Petroleum Asset eXcellence (PAX)?

More than all else, clean-slate asset strategies enable customization of our remaining four drivers based on whether an asset is going through growth or decline. Operators committed to building and maintaining additional capacity, such as capital-intensive facilities improvement programs, only where there are remaining reserves and future value potential, or they eliminate expensive optionality wherever the asset’s maturity makes it irrelevant to future value creation.

2. What is the leanest physical footprint for your asset?

The physical footprint of an asset has always been a major driver of project economics. With increasingly small and stranded reserves and limited discretionary spending, it has become the single largest factor in project break-evens. Additionally, the physical footprint shapes operational processes and determines the structural limits of operating cost optimization across asset lifecycles. Examples of these limits include deck space, number, and type of crane, storage and layout, and redundancy in installed equipment. We recommend that operators consider the total value of owning their physical footprint—in design and in operations.

For new builds, considering the total value of owning their physical footprint may lead to smaller, modular, unmanned or energy self-sufficient designs. A North Sea independent used a standard platform design to shorten the engineering process and achieve first gas within 18 months versus industry averages of 30 to 36 months. The standard topsides—developed for two marginal fields were usable in other fields within a comparable range of gas throughput. The modular jacket was suitable for similar shallow water resources. Solar and wind power generation with battery storage reduced air emissions and offered energy self-sufficiency. Standardization and modularity rationalized maintenance costs just as much as FEED capital. As routines were replicable across the portfolio, a standard campaign-based maintenance approach yielded material synergies in engineering, work preparation, and spares management.

For mature assets, standard subsea design and equipment improves the economic attractiveness of brownfield expansions. Besides, obsolescence, fatigue or corrosion issues can all serve as triggers to make the asset easier and more economical to maintain. One operator in West Africa replaced traditional flowlines with thermoplastic ones. With better corrosion resistance, higher asset integrity and longer life, these new materials drastically extended schedules for inspections and maintenance routines. In a different example, a North Sea late-life asset systematically challenged the equipment in place to reduce surplus capacity in power generation, compression, and storage vessels. The lower physical footprint eliminated 25 percent of required maintenance hours and allowed redeployment of the maintenance team to more pressing pre-Cessation-of-Production imperatives. With a total value of ownership approach, this operator tackled the growing divergence of needs from means in its initial operating envelopes, and structurally reduced its operating cost base.

3. How can you compress your workload?

In asset turnarounds, we commonly encounter over-reliance on time-driven maintenance philosophies. Equipment strategies are set to standard specifications and adapted marginally as assets move through steady-state production into decline. The outcome is inflated workloads and costs, combined with an operations and maintenance plan that does not adapt adequately to emerging reliability or integrity challenges. Our proprietary maintenance benchmarks indicate that there can be a 5 to 10 percentage point differential in production efficiency and 20 to 30 percentage point differential in maintenance costs between top quartile operators and the also-rans.

Success cases exercise both traditional and digital levers to optimize the overall operations and maintenance workload. Traditional choices include stepping away from a 100 percent inspection approach to risk-based strategies in mid-life assets or run-to-failure for late life ones. However, next-generation operations and maintenance is centred on equipment sensors for performance data, advanced analytics and machine learning to predict and avoid failures, with maintenance or replacement on an as-needed basis. This end-to-end digitally enabled system makes activity workloads smaller and more predictable, feeds into more efficient and economic management of materials and people, and levels the operational risk-return profile of an oil and gas business towards the steadier profile of a manufacturing one.

A mature asset operator makes timely interventions through failure prediction to reduce asset downtime. Predictive maintenance incorporates sensor data and condition monitoring results in a machine-learning algorithm, which recognizes patterns associated with different failure modes on a specific machine. As no two machines are alike, the learning algorithm can customize trigger points for failures on each individual piece of equipment, thus allowing maintenance teams to plan better, reduce the incidence and severity of failures, and compress the time to recovery. The operator has reduced downtime on critical machines by as much as 30 to 50 percent.

Most significantly, predictive techniques are redefining the scope and composition of maintenance activities, enabling organizations to have smaller maintenance teams and lower operating costs. Exhibit 3 shows the expected future impact for this mature asset operator.

Exhibit 3

Illustrative example – a full scale-up is expected to transform maintenance scope, efficiency and costs

Predictive techniques are relevant regardless of the life stage of an asset. However, operators may choose to match upfront investment with the remaining life of their assets. While an overhaul of multiple systems into a single platform may have a positive business case at an early-life asset, a mature asset may better use an integrated platform that consolidates scattered data from legacy systems and rapidly digitizes key operational workflows.

4. How can you multiply the work hours you obtain?

Upstream operators consistently appear middle of the pack in time-in-motion studies, reporting an average of 20 to 30 percent of a shift as productive. However, world-class process-based industries and leading upstream operators can extract 7 hours of value-added work in a 12-hour shift; in some cases, particularly in campaign-based interventions, they can achieve 8 to 10 hours of useful work per shift.

Lean tools continue to be the mainstay of improving productivity. In addition, the vision for next-generation operations and maintenance is to put the employee at the core, flipping the model from ‘thinking like the manager’ to ‘thinking like the technician.’ This means that anything in the way of the technician’s doing value-added work must be minimized, or where possible, automated.

At an offshore asset, we shadowed technicians to uncover their pain points. Three pain points emerged at the top:

  • A manual and substantial data reporting burden that went beyond industry compliance requirements: this trapped the offshore installation manager and supervisors at their desktops.

  • A time-based schedule and planned loading approach in compliance with company maintenance execution standards: often, this imposed twice as many work orders and doubled the time per work order relative to actual execution data. While the asset was plan compliant, the maintenance teams had effective surplus capacity.

  • Focus on a process rather than equipment or systems: this prompted compliance with complex process steps and reporting to relevant technical authorities over equipment care and ownership.

Addressing technician pain points along the maintenance execution process was the main lever for improving productivity. The operator reacted with three innovations:

  • Digitization of key workflows had the secondary benefit of allowing most compliance data to be tracked autonomously and routed to a secure site for reporting to the parent company or regulator. This freed up offshore supervision capacity. Gradual deployment of IoT and mobile devices over the next two years was expected to provide further relief through real-time reporting.

  • Time-based scheduling and plan loading was replaced with the use of actual execution data captured in digital work tracking systems. Surplus capacity in maintenance teams could be redeployed to liquidate maintenance backlogs or better utilized for standby work. The operator was beginning to implement next-generation control of work, with increased automation in integrated planning, permit-to-work processing, and work notifications.

  • Process simplification liberated front-line time and capacity. Simple engineering was delegated to an offshore engineer who supervised ‘find and fix’ and accelerated simple jobs without routing them back to a central team or contractor.

  • But front-line equipment care and ownership required organizational refinements. This brings us to the fifth driver of next-generation operating models.

Oil-gas-1536x1536-500_Standard

Rethinking the oil and gas organization Read the article

5. What is the minimum organization you need to achieve your business goals?

Upstream companies typically start and end reorganizations with the organization itself. Notwithstanding its limited impact on resourcing levels, this approach constrains companies’ abilities to visualize how they might adopt new technologies, such as digital tools, or introduce organizational agility, a premium functionality in our world of relentless change.4

Building a next-generation operations and maintenance team begins with drafting the minimum capabilities required for steady-state operations. At its most elemental, an operator takes a zero-based budgeting approach: desktop analyses and cross-functional scrums help set the size and shape of the smallest team with the skills to conduct the asset’s baseload activity set, and add incremental capacity only if there is a strong business case for it. So, while an early-life asset operator might aim for equipment familiarity through hands-on commissioning, a late-life asset operator would accommodate capacity to address integrity challenges. Even with this minimalist mindset, it is easy to rationalize why additional technicians should be on standby for unanticipated trips.

We have seen assets operating with teams less than half the prevailing norm, and specific activities, such as routine well interventions for reservoir data acquisition, run with team sizes of around 25 percent of what is typical. Three choices facilitate flexible access to the required capabilities:

  • Fluid teaming. Multiskilling through a second service role, combined operations and maintenance roles or a secondary competence is more talked of than implemented. Many technicians often have broader competences than trades-based staffing models allow. In next-generation operations and maintenance teams, we go further towards an agile organizational structure, designed around equipment ownership. For instance, an equipment improvement team is cross-functional with representation from challenge areas, such as engineering, maintenance or supply chain. It is self-managing and has end-to-end accountability for the reliability of its equipment. Each team sets out with a performance target associated with its equipment and has compensation tied to the results achieved.

  • Redefining skill requirements. As operators increasingly deploy digital technologies—improving work-scope predictability—unmanned operations become more feasible. An integrated remote operations centre staffed with data scientists and operations-skilled digital translators—who marshal advanced analytics models for production optimisation—is no longer inconceivable.

  • Use of innovative partnerships for non-core and peak load activities. Contracting is the traditional option for flexible access to skills. In a 21st-century organization, this might look more like a risk-sharing partnership. In a recent example, a large upstream oil and gas company established a long-term contract with two asset management contractors to increase production in a mature field. While reserves continued to be owned by the upstream company, the contractors operated under a cost recovery model with a bonus for how quickly they increased unit cash flows. Tailored alliances across the sector, with distinct contributions from participating upstream companies, can go beyond supply chain relationships. A recent merger of two operators combined the operational excellence of a leaner independent with a larger incumbent’s superior basin expertise. In the year following the transaction, the new entity nearly doubled production, providing greater financial robustness and a platform for long-term growth to both partners.

Ultimately, reorganizations must ensure access to the right talent within the asset’s business context. Organizational agility can achieve this without compromising process and personnel safety. Even with fluid teaming, the roles of the offshore installation manager or the site supervisor as safety custodian remain intact.


Achieving a continually evolving operating model will require new approaches to operational transformations, skill sets, and ways of working among the people who will make it happen. While the traditional transformation roadmap to arrive at well-defined goals is still relevant, an agile development and implementation process will be needed to accommodate greater collaboration and learning on the go. Multifunctional teams will work together on end-to-end processes to create new solutions, using shorter sprints to design minimum viable products, and being happy to fail fast as long as they learn in the process. This will put front-line teams and middle management at the heart of the transformation. And operators will have to invest in building both their belief in the value potential and their capability to deliver the required changes.

None of this will be easy, but it will be necessary if oil and gas operators are to attain the next wave of structural improvements amid the uncertainties of an ever-evolving industry.

December 2017, McKinsey & Company, www.mckinsey.com. Copyright (c) 2018 McKinsey & Company. All rights reserved. Reprinted by permission.

ExxonMobil to Join Stanford Strategic Energy Alliance

  • Builds on Global Climate and Energy Project’s 15 years of success
  • Strong science and exploratory research to develop low-carbon energy solutions
  • $20 million commitment in addition to ExxonMobil’s GCEP investment of more than $100 million
  • Expands company’s collaborative work with academic and research institutions around the world

IRVING, Texas–(BUSINESS WIRE)–Exxon Mobil Corporation (NYSE:XOM) today announced that it will become the first founding member of the new Stanford Strategic Energy Alliance, an initiative that will examine ways to improve energy access, security and technology while reducing impacts on the environment. As part of its commitment, ExxonMobil will contribute $20 million in funding over five years to research and develop lower-carbon energy solutions.

The Stanford Strategic Energy Alliance builds on the success of the Global Climate and Energy Project (GCEP), also led by Stanford, which focused exclusively on low-emissions, high-efficiency energy technologies. ExxonMobil has sponsored GCEP since its inception in 2002 with a commitment of $100 million and additional contributions toward specific projects. In its 15 years of work, GCEP has evolved into a pioneering collaboration of scientists, engineers, researchers and students focused on identifying breakthrough low greenhouse gas emission energy technologies that could be developed and deployed on a large scale.

“ExxonMobil has worked with Stanford to advance low-carbon technologies over the last 15 years, and we’re excited to be the first founding member of this new endeavor,” said Bruce March, president of the ExxonMobil Research and Engineering Company. “Identifying scalable solutions for addressing the dual challenge of supplying energy to meet global demand while minimizing the risk of climate change is one of our core missions. We are continuously looking for ways to improve existing supply options and manufacturing processes while managing carbon intensity.”

Since its creation, GCEP has sponsored more than 100 research programs in the United States, Europe, Australia, China and Japan, and has resulted in over 900 papers in leading journals and more than 1,200 presentations at conferences. Building on fundamental science, significant advances have been made in the areas of photovoltaic energy, renewable and lower carbon fossil fuels, batteries and fuel cells. More than 60 technologies have also been developed and 15 patents have been issued. Multiple companies have also started up as a direct result of or inspiration from GCEP research.

The new Stanford Strategic Energy Alliance will pair industry alliance members and Stanford professors who share common research objectives across the spectrum of energy topics from science and engineering to policy and business. Managed by the Stanford Precourt Institute for Energy, the alliance will also fund some early-stage research at the direction of its faculty leadership.

ExxonMobil’s support for the Stanford Strategic Energy Alliance expands the company’s collaborative efforts with other academic and research institutions that are focused on developing an array of new energy technologies, improving energy efficiency and reducing greenhouse gas emissions. The company currently works with about 80 universities in the United States, Europe and Asiato explore next-generation energy technologies, including founding members of MIT Energy InitiativePrinceton E-ffiliates Partnership and University of Texas at Austin Energy Institute.

Source: Exxon Mobil Corporation

ExxonMobil
Media Relations, 972-940-6007

RPSEA Outlines Oil & Gas Research Needs for the Next Decade

The nonprofit research Partnership to Secure Energy for America (RPSEAhas unveiled a comprehensive 10-year plan for advancing research into sustainable oil and gas technology that aims to help cement the status of the U.S. as a leading global producer well into the future.

The wish list of research needs addresses a diverse roster of topics that ranges widely from studies on streamlining the development of offshore reservoirs to improving well recovery in shale plays and advancing environmentally sensitive practices.

“No one knows what the energy industry will look like in the next 10 years, but we do know in order to maintain our leadership position, the United States must compete on a global basis, (and) take full advantage of rapidly evolving technology and address the variety of challenges we will face,” RPSEA President Tom Williams said in a press release.

The Research & Development Plan (R&D Plan) is being released at a critical point in the history of the U.S. oil industry.

Fueled by the shale revolution and development of complex deepwater reservoirs, U.S. oil production surged to a 37-year high of 10 million barrels per day in November and output is expected to continue climbing to a fresh all-time record this year, according to the federal Environmental Information Administration.

U.S. oil production hit a 37-year high of 10 million b/d in November 2017. Source: EIA

With output pushing higher and an oil-friendly administration in the White House, the need to focus on sustainable, environmentally conscious development practices is more apparent than ever.

The R&D Plan draws heavily on input from industry stakeholders and RPSEA’s network of subject matter experts, including universities, national laboratories, as well as large and small energy producers and consumers. It also builds on the foundation of RPSEA’s successful program in the past decade working with the industry, academia, and the Department of Energy National Energy Technology Laboratory (NETL).

Onshore Research Needs

Included in the research needs outlined in the R&D Plan are calls for studies into the most effective strategies and technologies for developing unconventional reservoirs, such as the Marcellus Shale in Appalachia, the Bakken Shale in North Dakota and the Eagle Ford Shale in Texas.

The report notes that the average U.S. shale well currently recovers less than 10% for oil production and 15% for gas production, making the enhancement of reservoir recovery an issue of great interest for all stakeholders. It suggests research into better reservoir characterization to improve the well design and wellbore placement to boost recovery.

As shale development increases, the R&D Plan also recommends examining of issues surrounding flowlines, pipelines, and stray gas especially in areas where population growth has occurred on top of old and sometimes abandoned flowlines that were not mapped or identified.

This need was highlighted last year by an incident in Firestone, Colorado. A home in relatively new Front Range neighborhood was destroyed in an explosion linked to an old flowline that was thought to be out of service. The accident led to two deaths and prompted state regulators to call for the inspection of wells and flowlines across the state.

“The domestic unconventional gas resource has dramatically altered the energy picture in the U.S.,” the report said. “As attention turns toward shale gas resources around the world, the technologies developed through this program and applied to the environmentally responsible development of domestic resources will keep U.S. companies and universities in the forefront of global unconventional resource development.”

The R&D Plan also included a call for documenting the impact of shale gas production on regional air and water quality, with proposed projects on environmental baseline monitoring, fugitive methane emissions and fracturing flow back water characterization.

Water management was highlighted as a universal issue, with the cost of recycling being an important factor. Though the report noted that advances are somewhat restricted by regulations, liability, risks, transportation, sourcing, and disposal. It also highlighted a need for research and better technologies to monitor and manage water disposal related to induced seismicity.

Offshore Research Needs

Offshore production research needs were also a subject of significance in the R&D plan. In recent years, several big deepwater developments have come online that pushed the technological boundaries of the industry to new limits and helped to propel production from the federal Gulf of Mexico to a record 1.7 million b/d in November, EIA data show.

Deepwater reservoirs are particularly challenging and costly to develop. They require years of advance planning and pose unique operating challenges and risks.  The R&D plan recommends further research into a variety of issues associated with this output to find ways to streamline the process of bringing new wells online while minimizing environmental impacts.

“The goal of Offshore Program is to develop environmentally sensitive, cost-effective technologies to identify and develop resources in increasingly challenging conditions and ensure that the understanding of the risks associated with deepwater operations keeps pace with the technologies that industry has developed,” the R&D Plan said.

Becoming a Safety Leader

The research model RPSEA has developed includes actively engaging stakeholders across the entire community of energy producers, researchers, technology providers, regulators and environmental groups.

And while the R&D Program was primarily developed to promote the safe delivery of energy resources to U.S. citizens, any discoveries could also be extended to oil and gas production in other countries across the world.

“While the U.S. is currently a leader in terms of the development of oil and gas (in particular, the onshore unconventional shale resources), other nations are beginning to see these resources as an important component of a plan to move toward a lower-carbon, sustainable energy mix,” Williams said.

Exxon Launches Multi-Pronged Approach to Reducing Methane Emissions

ExxonMobil is taking fugitive methane emissions seriously with a program designed to lower the volume of the greenhouse gas that is released from the company’s production and midstream sites across the US.

The program, launched in September, prioritizes actions at US sites operated by the company’s shale-focused subsidiary XTO Energy. The effort includes phasing out high-bleed pneumatic devices, research into new technologies designed to detect and reduce facility emissions, staff training, and a leak detection and repair program.

“We are implementing an enhanced leak detection and repair program across our production and midstream sites to continually reduce methane emissions, and are also evaluating opportunities to upgrade facilities and improve efficiency at both current and future sites,” XTO President Sara Ortwein said in a press release.

The program goes beyond measures required by federal and state laws and represents a substantial move by Exxon — the largest natural gas producer in the US — to set a higher bar for the entire industry.

Plan Details

The multi-pronged approach to reducing methane emissions begins with a focus on the wellhead and associated midstream infrastructure; The leak detection and repair program requirse every XTO division to survey production and midstream sites with optical gas imaging camera technology for leaks. Data collected by these surveys will then analyzed for frequency, trends and patterns with facilities and equipment that are found to be more prone to leaking becoming top repair priorities.

XTO is also starting a three-year plan to phase out the use of 1,250 high-bleed pneumatic devices across its US operations. The valves, which are typically found at older sites, are designed to periodically vent pressure buildup to maintain safety, system integrity and efficient operations. The ones considered ‘high bleed’ vent more often and at higher volume

The practice of addressing the most leak-prone equipment and high-bleed pneumatic devices first suggests that XTO’s program could yield notable improvements early on. That’s because the largest portion of methane emissions appears to come from a small number of sources, in much the same way that a small percentage of older cars is responsible for the largest share of automotive-exhaust pollution, according to a 2014 study published by the University of Texas and the Environmental Defense Fund, with participation from Exxon.

The new program also calls for managing planned events in ways that are designed to reduce the release of methane emissions into the atmosphere. For instance, field personal will now monitor and remain nearby during the manual liquid unloading process at well sites to close off all wellhead vents to the atmosphere. Liquid unloading is a process that involves removing liquid that has collected in equipment tubing and prevents natural gas from flowing up through the well.

In addition, a training effort focused on management approaches to overall fugitive emissions is being launched and will consider topics like pneumatic device integrity, leak detection and repair practices, and the sharing of best practices across the company.

XTO will also continue its practice of using green completions to minimize methane emissions at wells during the completion process by capturing or burning off flowback emissions instead of venting them into the atmosphere. It is also working to minimize the need to burn off or flare this gas by maximizing gas capture via pipeline, although some flaring will still happen at new developments where infrastructure investments are contingent on successful hydrocarbon development.

West Texas and New Mexico

XTO has already begun putting some of these practices to use in prolific fields in West Texas and New Mexico. Last year, the company completed a pilot project in the Midland Basin that tested new low-emission designs that use compressed air instead of natural gas to operate the pneumatic equipment that helps to regulate conditions such as level, flow, pressure and temperature. It said the results demonstrated the feasibility of using similar designs for new and existing central tank batteries to further eliminate methane emissions.

The company is also collaborating with ExxonMobil Upstream Research Company and third-party equipment manufacturers to develop state-of-the-art, low-cost, minimum-emissions equipment that could be used for future developments, particularly in the Delaware Basin. Parent company Exxon is also participating in a methane measurement reconciliation study with the Department of Energy’s National Renewable Energy Laboratory, and supporting research underway at Harvard, the University of Texas Energy Initiative, and Stanford University’s Natural Gas Initiative.

Legal Battles

Exxon’s expanded commitment to the environment comes as the company is facing an environmental legal battle in California. In July 2017, seven coastal communities filed suits in their local Superior Court systems alleging greenhouse gas emissions caused by Exxon and 17 other energy companies contributed to a warming planet, leading to coastal flooding, beach erosion and rising infrastructure costs. New York City followed California’s lead in January by filing its own lawsuit against the oil major and four other fossil fuel companies that seeks billions in damages to fund “climate change resiliency measures that the city needs to implement.”

Exxon’s Vice President of Public and Government Affairs for Suzanne McCarron addressed these global warming concerns in a January post on the company’s Energy Factor blog, saying “We believe the risk of climate change is real and we are committed to being part of the solution. That is why we have invested $8 billion since 2000 on energy efficiency and emissions reduction.”

In the meantime, the effort by these governmental bodies to wring money from the oil supermajor may ultimately be distracting from the bigger, overarching challenge we all face — that of securing energy to power a hungry world while coming up with technological solutions to reduce the risks posed by climate change.

The methane emissions reduction effort represents a step in the right direction for Exxon and serves as the latest indication that momentum to develop more sustainable oilfield practices is building across the industry.

Video

To Innovate, You Need to Go Places You’ve Never Been

A drone rises into the sky above the Permian Basin in West Texas. The ground operators and engineers monitor its flight path and collect its data transmissions. While this happens, the Drone tells us why it does what it does.

 

Published on https://www.shell.us/energy-and-innovation/shale-gas-and-oil/drone-development-permian-basin.html?cid=social%3Afacebook%3Adrone-unc%3Ajan2019&fbclid=IwAR3j1au345HxkKHM-XCSFUdcDnmhkDasUQ1MOX3sMON7BITGB1hN37pX5XI

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Continuous and unmanned aerial vehicle methane monitoring with a new digitally integrated platform – BHGE is unveiling LUMEN for oil and gas operators

  • At its 20th Annual Meeting in Florence, BHGE makes the commitment to reduce CO2 equivalent emissions 50 percent by 2030 and achieve net zero by 2050

  • BHGE will support customers’ efforts to reduce the carbon footprint of their operations by investing in its portfolio of lower carbon products and services

  • New and future technologies launched at the annual event include LUMEN, which is both a wireless ground-based and aerial drone-based methane detection system; as well as a turbine powered 100 percent by hydrogen

  • BHGE’s Gaffney, Cline and Associates has launched its own Carbon Management Practice, the first oil and gas consultancy to offer a quantitative assessment of the carbon intensity of oil and gas assets, evaluation of carbon solutions and the accreditation of emission reductions

FLORENCE, ITALY — 28 January 2019 – On the first day of its 20th Annual Meeting in Florence, Italy, Baker Hughes, a GE company (NYSE: BHGE), announced its commitment to reduce its CO2 equivalent (eq.) emissions 50 percent by 2030,* achieving net-zero CO2 eq. emissions by 2050.  The company also said it will invest in its portfolio of advanced technologies to assist customers with reducing their carbon footprint.

Net Zero Carbon Emissions

BHGE has already achieved a 26 percent reduction in its emissions since 2012 through a commitment to new technology and operational efficiencies.  BHGE will continue to employ a broad range of emissions reduction initiatives across manufacturing, supply chain, logistics, energy sourcing and generation.  BHGE has established a global additive manufacturing technology network with a mission to bring commercial-scale production closer to customers, reducing transportation impact and associated emissions.

“Oil and gas will continue to be an important part of the global energy mix, and BHGE is committed to investing in smarter technologies to advance the energy industry for the long-term,” said Lorenzo Simonelli, chairman and CEO of BHGE. “Managing carbon emissions is an important strategic focus for our business.   We believe we have an important role to play as an industry leader and partner.  BHGE has a long legacy of pushing the boundaries of technology and operating efficiency. Today we take this to the next level by committing to ambitious new goals for ourselves, and to provide lower carbon solutions expected by customers and society.”

New Carbon Management Practice

To further industry and customer efforts to reduce carbon emissions, BHGE’s Gaffney, Cline and Associates has launched a new Carbon Management Practice. This is the first oil and gas consultancy to offer a quantitative assessment of carbon intensity, evaluation of carbon solutions and the accreditation of emission reductions. This new practice helps governments, energy companies and the financial community understand and solve energy transition issues related to oil and gas resources, assets and investments.

Technology Partner to Customers

At its Annual Meeting, BHGE announced new and existing technologies that support operators’ efforts to reduce their carbon footprint:  

  • LUMEN, a full-suite of methane monitoring and inspection solutions capable of streaming live data from sensors to a cloud-based software dashboard for real-time results.  The platform consists of two seamlessly connected formats – a ground-based solar-powered wireless sensor network, and a drone-based system for over-air monitoring, – ensuring methane emissions rates and concentration levels are monitored and located as efficiently and accurately as possible. This builds on BHGE’s extensive portfolio of remote inspection and sensing technologies.

  • An agreement with H2U, Australia’s leading Hydrogen infrastructure developer, to configure BHGE’s NovaLT gas turbine generator technology to operate 100 percent on hydrogen for the Port Lincoln Project, a green hydrogen power plant facility in South Australia.

The new technologies build on BHGE’s expanding lower-carbon technology portfolio, which includes:

  • Modular Gas Processing: Modular gas processing at Nassiriya and Al Gharraf oilfields in Iraq will recover 200 million standard cubic feet per day of flare gas, reducing emissions by 5.7 million metric tons per year of CO2 equivalent, and monetizing the recovered gas. The recovered gas will be processed into dry gas, liquefied petroleum gas for cooking, and condensate, and will support domestic power generation as well as exports. An additional net 3.9 million metric tons of CO2 eq. emissions reductions are possible annually if incremental power generation is fueled by natural gas, displacing oil.  Flare gas recovery and use represent one of the largest emission reduction opportunities in the global oil & industry.

  • LM9000 Gas Turbine: BHGE’s most advanced aero-derivative gas turbine, introduced in 2017, was designed to allow the LNG train startup in the pressurized condition without venting process gas.  Its flexible fuel technology reduces emissions while eliminating water use in emissions abatement.  The LM9000 delivers 50 percent longer maintenance interval, 20 percent more power and 40 percent lower NOx emissions, resulting in 20 percent lower cost of ownership for LNG customers.

  • Integrated Compressor LineThis high-efficiency offshore compressor operates with zero emissions. It is driven by a high-speed electric motor in a single sealed casing and its rotor is levitated by active magnetic bearings (AMBs), allowing exceptional efficiency and reliability.

  • flare.iQ: flare.IQ™ provides highly accurate, near-continuous control of downstream flare performance by optimizing combustion efficiency, allowing operators to reduce flaring-related emissions by up to 12,100 metric tons of CO2 equivalent per flare annually. If deployed globally, flare.iQ could reduce annual emissions by 190 million metric tons of CO2 eq.

  • NextSource Modular CO2 Capture:  NextSource converts thermal energy from rich burn Waukesha engine exhaust to provide low-cost CO2 for oil and gas consumers. In the process, each four-engine pad reduces emissions by 16,200 metric tons of CO2 equivalent annually or 60 percent compared to the no-capture scenario. In addition, because CO2 is captured near the well site, emissions are avoided from not having to transport liquid CO2 from a remote location to the well site.

Visit https://annualmeeting.bhge.com to learn more about the Florence event including the conference agenda and speakers guide, and where the full proceedings from the Annual Meeting will be shared at the close of the event.

**BHGE’s 2030 emissions reduction targets and performance are based on scope 1 & 2 emissions for 2017 and baseline year 2012, as reported to the Carbon Disclosure Project..

WEBINAR | Combined Heat and Power for the Modern Oilfield

CHP for the Modern Oilfield
On-Site Power Generation and Thermal Energy for Oilfield Operations
Recorded September 13, 2018
Presented by the US Department of Energy Upper-west CHP Technical Assistance Partnership

The Oilfield is evolving to exploit the many advantages of electrification, automation and other technological advances to reduce cost, enhance safety, and improve efficiency. The electrified oilfield presents enormous opportunity to realize value from on-site power generation using locally-produced natural gas.

Combined Heat and Power (CHP) provides both electric power and thermal energy (heat) from a single on-site source, such as a turbine or reciprocating engine. Learn about CHP applications and benefits for reliable on-site power and utilizing recovered heat for produced water management, enhanced oil recovery, and other purposes

View Webinar here

CHP offers many advantages of energy efficiency and resilience. Recognizing this, the US Department of Energy (DOE) provides funding to assist public and private entities to implement CHP at facilities of many types. The DOE CHP Technical Assistance Partnerships (TAP) program promotes CHP technology solutions for the industrial and manufacturing sectors, critical infrastructure, institutions, commercial facilities, and utilities seeking to reap the many benefits of CHP. HARC is home to two regional CHP TAPs: the Southcentral Region, serving Texas, Louisiana, Arkansas, Oklahoma, and Arizona; and the Upper-West Region, encompassing Montana, South Dakota, North Dakota, Wyoming, Utah, and Colorado.

The US Department of Energy Southcentral and Upper-West CHP Technical Assistance Partnerships. Through this program, the TAP offers site qualification screenings, feasibility studies, third party project development support, as well as outreach and education to potential CHP end-users. The HARC team is ready to work with you as you consider CHP. Learn more at http://www.harcresearch.org/work/CHP_TAP or contact Gavin Dillingham, PhD, Director of the Southcentral and Upper-West CHP TAP Programs at [email protected] or 281-364-6045.

Quasar 2 – New Flare Stack Monitoring System

The new flare stack monitoring system from LumaSense Technologies is designed to monitor pilot flames and flared gases for elevated flare stacks. Additional applications include: Gas assist flares, Staged flares, and Offshore flares. Quasar 2 is available in “Basic” and “Advanced” models.

Safe flare operation and environmental protection require reliable and accurate flare pilot monitoring. Generally, all flare pilots are monitored with thermocouples. However, thermocouples fail due to thermal shock, extreme heat and vibrations during flaring events. The requirement for pilot monitoring beyond the normal life of pilot thermocouples has driven the market need for alternative methods and installation of redundant methods of pilot monitoring in addition standard pilot thermocouples. Regional flare governmental permitting rules driven by environmental protection, health and safety guidelines for global flare operation have had a large impact on the increasing market need for IR pilot monitoring systems.

The E²T Quasar 2 series are monitoring and detection instruments designed for continuous duty monitoring of pilot flame and flared gases from flares. The base system provides low-cost basic flare pilot monitoring capabilities. The advanced model has an intensity meter with 2 set points that allow monitoring of both the pilot and flaring status signals from the same unit. Additional add-on features are available for a configurable product to meet a wide range of client flare types, monitoring requirements and budget. High Resolution sight-through optical system and selection of various spot sizes enables the Quasar 2 system to be positioned as far as 1/4 mile (400 m) from the stack being monitored. Alignment on the target is accomplished through bead and notch aiming and signal amplitude in combination with a stable M-4 heavy duty swivel mount. Custom electronics adapt to target movement, varying luminosity and most climate conditions. The alarm delay circuit can be adjusted for a specific location or application, eliminating false alarms from temporary loss of signal due to intermittent flames, adverse weather and wind.

The system is complete with internal cooling base, air purge tube and swivel mount. An optional M-8 pedestal stand allows for easy stable system mounting. With over installations at over 550 petrochemical facilities worldwide, customers know they can trust LumaSense E²T line of petrochemical infrared sensors.

LumaSense Technologies, Inc.

Published on Aug 1, 2018

For more information, visit: https://info.lumasenseinc.com/q2

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