The future is now: How oil and gas companies can decarbonize

As the pressure to act on climate change builds, the industry should consider a range of options.

If the world is to come anywhere near to meeting its climate-change goals, the oil and gas (O&G) industry will have to play a big part (Exhibit 1). The industry’s operations account for 9 percent of all human-made greenhouse gas (GHG) emissions. In addition, it produces the fuels that create another 33 percent of global emissions (Exhibit 2).

Several trends are focusing on the minds of industry executives. One is that investors are pushing companies to disclose consistent, comparable, and reliable data. Activist shareholders, for example, are challenging the US- and Europe-based oil majors on their climate policies and emissions-reduction plans.1 Investors are also increasingly conscious of environmental issues. In the five markets examined by the Global Sustainable Investment Alliance—Australia and New Zealand, Canada, Europe, Japan, and the United States—sustainable investments reached assets of $30.7 trillion in early 2018, one-third of total investment. At September’s UN climate summit, an alliance of the world’s largest pension funds and insurers (representing $2.4 trillion in assets) committed itself to transition its portfolios to net-zero emissions by 2050.2

At the same time, renewable technologies have been getting cheaper. In the United States, the cost of solar—both photovoltaics (PV) and utility-scale—has fallen more than 70 percent since 2011, and the cost of wind by almost two-thirds. By 2025, they could be competitive with natural gas-based power generation in many more regions.

Other forces are also coming into play. Although there is still no global market, carbon taxes or trading systems cover 20 percent of worldwide emissions, compared with 15 percent in 2017, according to the World Bank.3 Many European governments plan to implement binding GHG emissions targets and are drawing up national energy and climate plans.

Options for the oil and gas sector

To play its part in mitigating climate change to the degree required, the oil and gas sector must reduce its emissions by at least 3.4 gigatons of carbon dioxide equivalent (GtCO2e) a year by 2050, compared with “business as usual” (currently planned policies or technologies)—a 90 percent reduction in current emissions. Reaching this target would clearly be easier if the use of oil and gas declined. But even if demand doesn’t fall much, the sector can abate the majority of its emissions, at an average cost of less than $50 per ton of carbon dioxide equivalent (tCO2e), by prioritizing the most cost-effective interventions. Process changes and minor adjustments that help companies reduce their energy consumption will promote the least expensive abatement options.

The specific initiatives a company chooses to reduce its emissions will depend on factors such as its geography, asset mix (offshore versus onshore, gas versus oil, upstream versus downstream), and local policies and practices (regulations, carbon pricing, the availability of renewables, and the central grid’s reliability and proximity). Already, many companies have adopted techniques that can substantially decarbonize operations—for example, improved maintenance routines to reduce intermittent flaring and vapor-recovery units to reduce methane leaks (Exhibit 3). Cutting emissions is not necessarily expensive. An onshore operator found that about 40 percent of the initiatives it identified had a positive net present value (NPV) at current prices and an additional 30 percent if it imposed an internal carbon price of $40/tCO2e on its operations.

One option is to implement initiatives that offset emissions by tapping into natural carbon sinks, including oceans, plants, forests, and soil; these remove GHGs from the atmosphere and reduce their concentration in the air. Plants and trees sequester around 2.4 billion tons of CO2 a year.4 The Italian energy giant ENI has announced programs to plant 20 million acres (four times the size of Wales) of forest in Africa to serve as a carbon sink. Other companies are looking at how to fund these offset programs; Shell offers Dutch consumers the possibility of paying to offset emissions from retail fuel. The cost of carbon sinks is uncertain; estimates range from $6 to $120 per tCO2e in 2030, depending on the source and the sequestration target.

Any company can invest in offsets. On the whole, however, upstream and downstream operators have different sets of options at their disposal.

What upstream operators can do

Upstream operations account for two-thirds of sector-specific emissions. Below, we discuss some ways in which oil and gas companies are taking action. The economics will vary greatly, depending on the option and local conditions.

Changing power sources. One oil and gas company is using on-site renewable-power generation to provide a cost-effective alternative to diesel fuel. By replacing generators with a solar PV and battery setup, the company not only reduced emissions significantly but also broke even on its investment in five years. Connecting onshore or nearshore rigs and platforms to the central grid (as opposed to decentralized diesel generation) can also work well: for example, in its drive for electrification, Equinor recently connected its Johan Sverdrup field, which lies 140 kilometers offshore, to the grid. If upstream producers electrified most of their operations, that could add up to 720 tCO2e a year in abatement by 2050, at an estimated cost of $10/tCO2e, depending on local electricity costs.

Reducing fugitive emissions. Companies can cut emissions of methane, a powerful GHG, by improving leak detection and repair (LDAR), installing vapor-recovery units (VRU), or applying the best available technology (such as double mechanical seals on pumps, dry gas seals on compressors, and carbon packing ring sets on valve stems).5 One company replaced the seals in pressure-safety valves, which had been found to be a frequent source of leaks, and then was able to monetize these streams of saved or captured gas. We estimate that reducing fugitive emissions and flaring could contribute 1.5 GtCO2e in annual abatement by 2050, at a cost of less than $15/tCO2e.

Electrifying equipment. One company replaced gas boilers with electric steam-production systems, including high-pressure storage for nighttime steam supply, to support separation units. The project will pay for itself in less than ten years. In many circumstances, there is already a good business case, on purely financial grounds, for combining the use of solar and gas in place of conventional boilers.

Reducing nonroutine flaring through improved reliability. One operator found that 70 percent of all flaring emissions came from nonroutine flaring, mainly as a result of poor reliability. It, therefore, focused on improving its operations—for example, by carrying out predictive maintenance and replacing equipment. These actions not only reduce emissions but also raised production. Best-in-class operators are making significant strides in reliability thanks to area-based maintenance and multiskilling. Predictive analytics can reduce the frequency of outages to compressors or other equipment.

Reducing routine flaring through improved additional gas processing and infrastructure. While some flaring may be unavoidable, the capacity constraints of infrastructure can lead to more than either companies or the public might want. In the Permian Basin, for example, a record of 661 million cubic feet a day (mcf/d) was flared in the first quarter of 2019. Addressing this challenge requires additional gas-processing facilities, as well as gathering and transport infrastructure. The Gulf Coast Express natural-gas pipeline, which went operational in September, will help. An additional 16 billion cubic feet a day (bcf/d) of planned capacity increases on pipelines from the Permian to the Gulf Coast is now under discussion.

Increasing carbon capture, use, and storage (CCUS). While this technology is projected to play only a minor role in the sector’s overall decarbonization, O&G players can still significantly influence its adoption and development. There are 19 large-scale CCUS facilities in commercial operation; four more are under construction and another 28 in development. There are also a number of demonstration and pilot projects. Together, plants under construction and in operation can capture and store about 40 MtCO2e a year. Total CCUS capacity could increase by as much as 200 times by 2050. In this market, the oil industry is well placed to lead because it already uses carbon captured via CCUS for use in enhanced oil recovery (EOR). That oil is also less emissions-intensive than the conventionally extracted variety.

A number of countries are looking to accelerate CCUS development. In 2018, for example, the US Congress passed a provision (45Q) increasing the tax credit that power plants and industries can take for either storing or using captured carbon. Congress is considering a bill, known as USE IT, to support the construction of CCUS facilities and CO2 pipelines and to finance research on direct-air capture. The business case for CCUS works only under specific economic conditions, such as tax relief or the imposition of a carbon price. Without some kind of regulatory framework, CCUS does not create value in and of itself.

CCUS costs $20/tCO2e for selected processes in the oil and gas sector but as much as $100 to $200/tCO2e in other industries, such as cement. One undertaking to watch is the Clean Gas Project in northern England, where a consortium of six oil and gas companies is building what could be the first commercial natural-gas plant with full CCUS capacity.

Rebalancing portfolios. Operators are starting to take a close look at their upstream portfolio choices. The highest-emitting reservoirs are nearly three times more emissions-intensive than the lowest. For example, complex reservoirs—highly viscous, in deep or ultradeep water, compartmentalized, or high pressure and temperature—may be at a structural emissions disadvantage. They may, therefore, become increasingly unattractive to develop in the future.

What downstream operators can do

Downstream operators are exploring many of the same ideas, such as energy efficiency and the electrification of low- to medium-temperature heat and energy. But they have distinctive options as well.

Energy efficiency. Efficiency is a factor in every part of the industry, of course, but new downstream-specific technologies can make a big difference. Waste-heat-recovery technology and medium-temperature heat pumps in refineries, for example, reduce the amount of primary energy used in distillation. One company saved €15 million in capital expenditures by forecasting its required steam usage hour by hour and incorporating this into a thermodynamic model to determine the required specifications for replacement equipment.

Green hydrogen. Hydrogen production through electrolysis has become both more technically advanced and less expensive. Bloomberg New Energy Finance estimates that the cost of hydrogen could drop as much as two-thirds by 2050. Using renewable energy rather than steam methane reforming (SMR) to power the electrolysis could offer refineries a way to reduce emissions—a result known as “green hydrogen.” An alternative, “blue hydrogen,” uses SMR plus CCUS. The attractiveness of the different technologies depends on the local economies—in particular, the availability of cheap storage capacity for CCUS or cheap renewable electricity.

Green hydrogen is not a speculative technology in oil and gas. Shell and ITM Power, a UK-based energy-storage and clean-fuel company are building the world’s largest hydrogen electrolysis plant at a German refinery, with support from the European Union. Revenue will come from selling hydrogen to the refinery, which will use it for processing and upgrading its products and for grid-balancing payments to the German transmission system. That business model justifies the installation.6

High-temperature electric cracking. In refining, several pilot projects use electric coils (instead of fuel gas) to provide heat. The technology is still at an early stage and small in scale. Moreover, the economics are sensitive to the price of electricity compared with gas and to the options for selling the fuel gas. Those economics improve if the investment is coordinated with the natural investment cycle to support additional capital expenditures—and, of course, if power can be purchased or generated under favorable financial terms.

Greener feedstocks. Replacing some conventional-oil feedstocks in refineries with biobased feedstocks or recycled-plastic materials (initially, through pyrolysis or gasification) would also reduce emissions—not only Scope 1 but also, to a large extent, Scope 3 emissions. In an increasingly decarbonizing world, this may extend the lifetime of refining assets.


The oil and gas sector will play an important role in the global energy transition; how it will face that future is a matter of strategy. As transparency increases, so may expectations. Customers, employees, and investors are already starting to distinguish the leaders from the laggards. Oil and gas companies that get ahead of the curve could find themselves better positioned for change.

This article is part of a series on energy transition and decarbonization.

About the author(s)

Chantal Beck is a partner in McKinsey’s London office; Sahar Rashidbeigi is a consultant in Amsterdam, where Occo Roelofsen is a senior partner and Eveline Speelman is an associate partner.

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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 gdillingham@harcresearch.org 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

YouTube

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

Secrets of the Deep: The Stones Metocean Monitoring Project | Sustainability at Shell

Shell has opened up parts of its Stones Deepwater mooring line to universities and research institutions. The Stones Metocean Monitoring Project provides access to data – unreachable until now – helping to build scientific understanding of the Gulf of Mexico’s role in global climate and ocean circulation.

Transcript: https://s00.static-shell.com/content/…

Welcome to Shell’s official YouTube channel. Subscribe here to learn about the future of energy, see our new technology and innovation in action or watch highlights from our major projects around the world. Here you’ll also find videos on jobs and careers, motorsports, the Shell Eco-marathon as well as new products like Shell V-Power. If you have any thoughts or questions, please comment, like or share. Together we can #makethefuture

Visit our Website: http://www.shell.com/

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Published by Shell on Nov 29, 2017

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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 Info@EcoVaporRS.com to see if ZerO2 is right for your operations and if you’re ready to Flare Less, Sell More.

Case Study Permian Basin

 

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