Between the Poles

Pilot project to create national map of UK energy infrastructure launched

A proof-of-concept project to develop a National Energy Systems Map (NESM) has been launched by the UK’s electricity and gas networks. The pilot project will give customers information about energy network assets, where those assets are located as well as who owns them. This project is a result of a core recommendation of the Energy Data Taskforce for the development of a digital system map of the UK energy network infrastructure with the overall goal of developing a full digital twin of the UK energy system.

Background

In October 2018, the Department for Business, Energy and Industrial Strategy of the UK government launched the Energy Data Taskforce, led by Energy Systems Catapult and supported by Ofgem and Innovate UK.  The objective of the task force was to determine how to release the power of data within the UK energy system. The final report A strategy for a Modern Digitalised Energy System provided a suite of recommendations on how data can contribute to developing and maintaining a decarbonized, decentralized and efficient energy system.

In most of world's major economies energy is increasingly decentralized increasingly relying on distributed energy resources (DER). Many assets such as electric vehicles, electric storage heaters and home batteries are capable of not only of consuming power but also able to generate it.  Modern assets are smart and able to signal and receive signals from network operators. Reducing the carbon content of power generation is a worldwide objective supported by governments, regulators and the utility industry.  New business models for utilities are emerging which reflect this new grid.  The UK government sees data as the key to unlocking the potential of the new grid. Transparent, accessible, interoperable and accurate data is seen as key to enabling network operators to adapt to and exploit the opportunities created by the new grid.

In the current energy system there are barriers to the effective use of data; no common data standards, no openly shared data repository and a culture of data hoarding rather than sharing.  It is estimated that a smart and flexible system can contribute to cumulative savings of up to £40 billion by 2050.

Development of a national digital energy map

One of the key recommendations of the task force is the development of a unified digital system map of the UK energy system. Such a map is intended to make infrastructure data accessible to all, to lower the barrier to entry and enable developers to create new solutions and validate new business models. Interoperability of network data is intended to provide networks, Ofgem and developers with efficiency benefits reducing data preparation and translation requirements.The digital energy system map will become one of the three data building blocks that will transform the energy system; a data catalogue which will provide a single, searchable location for energy system datasets, an asset registration strategy for identifying assets, and the digital system map that will provide a digital representation of the UK energy system.

The list of actions of the energy digitalization strategy in the recent Digitalising our energy system for net zero: Strategy and Action Plan 2021 includes the procurement of a National Energy System Map, with a proof of concept delivered by Q4 2021. The map will initially present datasets shared by network companies but is intended to grow and evolve with the addition of other energy sector data and potentially data from other sectors. To begin the implementation of this objective the Energy Networks Association has kicked off the development of a National Energy System Map for mainland UK that initially will encompass electric power and gas network data.  It is intended that this energy system data will be made publicly available as a digital map. The Energy Networks Association intends to deliver a proof of concept of a national energy system map in Q4 2021.

It is foreseen that a digital energy system system map will provide significant benefits; more efficient planning of renewable energy projects and future energy system infrastructure, more rapid development of new business models for energy, data standardization and interoperability, and increased energy system resilience through better system visibility.  In addition it will provide a foundation for the development of a digital twin of the UK's energy network.

Inertial locating to accurately map LIVE underground gas distribution utilities is a game changer

Inertial locating is an innovative technology that is used to accurately map underground pipe networks.  But to date the technology has required non-pressurized pipes.  Now a PHMSA-sponsored project has demonstrated that the technology can be applied to small-diameter pressurized gas lines with no disruption of service to customers.

The Reduct DuctRunner inertial mapping technology, about which I have blogged previously, allows mapping networks of (unpressurized) pipes with various diameters for distances of up to 2 km (1.25 Miles) with a precision of 15 cm (6 Inches) horizontally and vertically.

As the underground congestion increases, accurate mapping data of gas infrastructure is very critical for ensuring public safety. To improve underground pipeline locating tool applicability, a recent technology development and demonstration project was sponsored by the Pipeline and Hazardous Materials Safety Administration (PHMSA) and Operations Technology Development (OTD). The project was performed by a partnership between the Gas Technology Institute (GTI), Reduct and PRISUM Technologies (Condux International) and has shown that inertial mapping technology can now be inserted through a vertical Hot Tap Entry (HTE) for mapping live (pressurized) gas pipe networks as small as 2 inches (5 cm), with no disruption in service to downstream gas customers.

Currently best practices for recording the location of new underground infrastructure are to survey it after installation and before covering the trench. Appropriate survey tools are total stations, RTK, and LiDAR. However, for (deeper lying) existing infrastructure these technologies cannot be used. Also, trenchless technology is increasingly being used with the result that cross bores have become a major problem in many jurisdictions. An innovative technology that is being increasingly applied to locating existing pipe networks or those installed by way of horizontal drilling is inertial locating. Using this technology, it is possible to map networks of (empty) pipes with diameters ranging from 29 mm (1.1 inches) and above for distances of up to 2 km ( 1.25 Miles)) with a precision of up to 15 cm (6 Inches) in XYZ. The output of such a system is a 3D model.

Whereas conventional electromagnetic (EM) and ground penetrating radar (GPR) technologies have proven their value, they both require "boots on the pavement" and each has deficiencies that limits its applicability. EM methods only work for conductive materials, are generally not reliable for measuring depth and severed tracer wires for plastic pipes are a common problem. Soil conditions, nearby electromagnetic noise sources, and accessibility limits the usefulness of GPR.

Inertial mapping relies on a battery powered autonomous probe (no cable is required) with on-board gyroscopes, accelerometers, and odometers. The mapping tool records changes in direction and speed at a hundred samples per second to create an accurate, high frequency 3D profile of the pipe segment being traversed. Inertial mapping avoids the major limitations of surface-based EM and GPR techniques; it is not sensitive to soil conditions and extraneous electromagnetic noise, works with all types of pipe materials and is safe because it does not require boots on the pavement.

The significant breakthrough realized in this PHMSA-sponsored project is for the mapping probe to enter a pressurized small diameter pipe through a standard vertical hot tap and making the 90-degree turn into the mapping direction. This eliminates the need to disrupt service to customers because the pipe remains pressurized. The Reduct/GTI/Prisum partnership successfully demonstrated the new solution by mapping several 2 inch (5 cm) and 4 inch (10 cm) gas pipes owned by gas companies operating in the Chicago area. The longest run performed during these demonstrations was 300 feet (100 metres) in each direction but the Ductrunner developers believe this distance can be increased significantly.

This latest advance in inertial mapping dramatically broadens the applicability of the technology and represents a major breakthrough in mapping underground pipe networks of various sizes and in different environments. It is expected that the first commercial units of the live gas line solution will become commercially available within months.

Satellite able to measure methane emissions from individual facilities launched

Last night, September 2 at 11:51 p.m. EDT at the Arianespace satellite launch base in Kourou, French Guiana (UTC-3) the VV16 mission launched 53 satellites, ranging in weight from 145 kg to 7 kg.  Among them was GHGSAT-C1 or "Iris", a 16 kg Canadian satellite that detects methane emissions from specific facilities at high resolution.

Background

Source Nature 14 July 2020

Annual emissions of methane (CH4) have risen by almost 10% in the past two decades primarily resulting from emissions from the oil and gas industry and livestock. A recent Environmental Defense Fund (EDF) study concluded that methane emissions from the U.S. oil and natural gas supply chain in 2015 amounted to about 2.3% of gross U.S. gas production and are about 60% higher than EPA estimates.

A 2016 study found that just a few natural gas wells account for more than half of the total volume of leaked methane gas in the United States. An extensive aerial infrared camera survey of 8000 production sites in seven U.S. oil and gas basins found that 4% of surveyed sites had one or more observable methane high-rate emission plumes. Furthermore the large variability in methane emissions for similar equipment and facilities in different geographies supports the hypothesis that equipment malfunction is a major source of emissions. To identify the sources of methane emissions oil and gas companies are increasingly attempting to detect and monitor emissions from their facilities including oil and gas wells, tank farms, and compressor stations.

An additional important business driver is the global carbon market which is currently estimated to be about $50B and growing. This provides a financial motivation for industrial emitters to measure and manage their emissions.

Until recently methane emissions have been measured on the ground in a a slow, laborious process using a hand-held scanner. Government-funded aircraft overflights or satellites have captured emissions over broad areas but with insufficient resolution to identify individual facilities as sources.

Satellite-based methane emissions measurement

In 2016 a privately-funded startup GHGSat launched a proof-of-concept cubesat named "Claire" weighing 15 kg to measure methane emissions from individual oil and gas wells, refineries, compressor stations, landfills, animal feedlots, rice paddies, and natural sources. The objective was to provide a satellite-based methane measuring device that would enable private industry to estimate emissions from its own facilities anywhere in the world. About the size of a microwave oven Claire orbits the Earth every 90 minutes. Its field of view is 12 km x 12 km and it has a spatial resolution of about 50 metres. Claire is able to measure emissions from over 1,000 sites per year.  The GHGSat-C1 or "Iris" satellite that was just launched has higher resolution (25 metres) and will be able to measure emissions much more rapidly with a 10x performance improvement compared to Claire.

Innovative solution efficiently captures accurate underground utility as-builts during construction

Most of underground utility damage during construction is attributable to incomplete, inaccurate and out of date records and network documentation. This data is the result of an inefficient, error-prone, and paper-based information flow from engineering, through construction crews, and resulting in "as-builts" of uncertain quality which eventually form the utility's repository of record, typically in a GIS.  Recently a mobile solution has been developed that ensures that centimetre-level accurate as-builts are efficiently captured in the field in real-time. By digitalizing and automating the collection and validation of all construction data, accurate and up-to-date as-builts become the new normal.  Already used by over half of the 20 largest energy companies in the US, the Locusview system is being extended to support natural gas utilities, electric power utilities and telecom.

Background

Without accurate maps of underground infrastructure, every construction project has the potential to become an expensive disaster site. In the U.S. there are between 400,000 and 800,000 incidents of underground utility damage every year. Every year there are injuries and fatalities attributable to underground utility damage during construction. According to the Federal Highway Administration (FHWA) missing or inaccurate location information about underground utilities is a major source of highway construction project delays. The drag on the U.S. economy resulting from underground utility damage is estimated to be at least $50 billion annually.

Inefficient, error prone construction information flow

90% of underground utility damage during construction is attributable to incomplete, inaccurate and out of date records maintained by utilities and telecoms as well as data format issues including paper and digital ink (pdf).  The reason for unreliable records of network infrastructure can be found in an information flow that is found at every utility and telecom.

The design-build-maintain information flow begins with an engineer and drafter producing a design, typically a CAD drawing, which is printed for construction contractors to use in the field in installing new underground network infrastructure. Typically the design is based solely on above-ground surveys because information about existing underground infrastructure is unreliable or missing. The construction contractor may attempt to follow the paper design drawing, but for a variety of reasons what actually ends up in the ground differs from what was designed.  The design drawing, nominally an "as-built" but typically an “as-designed”, is then returned to the records management/network documentation group who enter it into the utility's GIS where it forms the permanent record of the utility or telecom's network infrastructure. This process is slow and error-prone and backlogs of as-builts waiting to be entered into the GIS stretch into months. The result is that utility and telecom GIS data is often inaccurate, out-of-date and incomplete.

Accurate as-builts are becoming mandatory

To address the problem of unreliable as-builts and the associated human and economic consequences several governments have enacted legislation and regulations requiring the submission of accurate as-builts.  Montana has recently revised its statutes governing the installation of utilities on state highway right-of-ways.  An updated Administrative Rule mandates that as part of a new permitting process accurate electronic as-builts must be submitted to the Montana Department of Transportation (MDT) upon completion of construction.  To ensure accuracy the regulations require that the as-builts be stamped by a licensed professional engineer (PE) or professional land surveyor (PLS). 

In 2017 the Singapore Land Authority (SLA) released a standard and specifications for the procedure and practice of utility surveying in Singapore.  The standard specifies that after installing utilities and prior to filling the trenches an as-built survey must be performed by a registered surveyor to capture the location of the utilities with horizontal accuracy of ±100mm and vertical accuracy of ±100mm.  In addition the standard specifically identifies the survey equipment to be used; total station, GNSS Real Time Kinematic (RTK), or 3D laser scanning.  This standard is not mandated, but provides a baseline to be incorporated in all government construction contracts.

In response to the requirement for accurate as-builts, the challenge for contractors is to capture accurate as-builts without adding to field crew workload and without impact to project schedules.

Digitalizing the construction information flow

Locusview was founded in 2014 as a spin-out of the US Gas Technology Institute (GTI) with industry funding to develop next-generation digital construction technology for the energy and telecom industry

Locusview has adopted a paperless, digital approach based on a mobile app that makes field crews the nexus for efficiently capturing accurate as-built information.  The user-friendly mobile application makes it easy and even attractive for crews in the field to move from a manual, paper-based process to one in which all construction data is digitally captured and validated in real-time during construction.  In addition to ensuring that as-builts accurately represent what was actually built in the field, this approach reduces time and costs in field data collection, reduces the time required to prepare as-builts for submission, and ensures that data gets into the GIS faster.

During construction field crews use the Locusview Mobile app with high accuracy GPS and barcode scanners to capture as-builts, track material usage, capture photos and support other field operations such as joints, splices and welds. But the app doesn’t just capture the asset information, it also validates that the information is complete and accurate according to the company’s data requirements and construction standards. Locusview captures material data faster and more accurately with automated feature creation and attribute generation using barcode scanning. In the case of gas utilities information on all welds and joints needs to be recorded because if done incorrectly welds and joints can lead to leaks and other problems. Locusview helps ensure that these processes are carried out correctly by capturing real-time pictures and by validating welder qualifications (OQ).

High accuracy GPS is implemented in several ways.  RTK base stations can be used for real-time high accuracy GPS. In GPS denied areas a laser range finder can be deployed. Alternatively control points can be used to ensure accurate georeferencing.

Back in the office the Locusview Web application enables visibility into the real-time status of projects, making it easier to assess progress and to project revenue streams. It also provides for data validation with automated warnings and notifications of violations; review and approve pre-configured check lists; exporting data to GIS, ERP and asset management applications; reports generation and project closeout.

Benefits

There are several critically important benefits that Locusview provides.  Most critically it provides for real-time reality capture, ensuring construction quality by enabling survey-grade accurate location, attributes and material data to be recorded by construction crews as new infrastructure is installed.  This ensures that as-builts are accurate and material usage is verified and traceable. It reduces the time to prepare as-builts for submission and speeds up the process of getting the as-built information into the utility's GIS by up to 70%, which is also crucial for emergency repairs. Having full visibility over the project’s status information in real-time using Locusview’s web tool makes it easier to track project progress and to project revenue streams. The field visibility also enables supervising the work remotely, which is helpful during Covid-19 times. In addition, time and costs are reduced for capturing and managing construction data by eliminating manual paper-based processes.

Just as importantly Locusview ensures that field construction information is captured efficiently. Maintaining a survey team on site to survey newly installed pipes and cables can be prohibitively expensive especially for smaller projects.  In actual projects it has been found that Locusview can reduce surveying costs by 50%.

In summary, utilities and telecoms use the technology to build a high-quality digital twin, to support asset management strategies and to ensure regulatory compliance.

Electric power case study

VPI, a Charge company, specializes in the construction of utility-grade electric power distribution infrastructure. During a recent major project involving 35,000 feet of open trenches and 35 construction sites for a large electric power utility in California the as-built requirements changed for both above and below-ground distribution infrastructure. Among the new requirements: as-built locations had to be accurate to ± 0.2 feet (± 6 cm).   One of VPI's major concerns was the cost of keeping a professional survey crew on-site at all times to capture the location of infrastructure to survey accuracy.

VPI looked for an alternative that would lower costs and provide the flexibility of not having to coordinate with outside survey crews.  VPI's main concerns were how to efficiently meet the high accuracy requirements, how to optimize the training and education of field staff, and avoiding adding to the work load of their field crews.

Locusview implemented their solution for VPI to meet the new high-accuracy GPS as-builting requirement that included the mobile app, web app and additional RTK base station coverage. The mobile app was found to be easy-to-use after only four hours of training for field crews. Most importantly using the mobile app instead of a traditional survey crew did not add to field crew workload and was able to be implemented without impact to schedule. Remarkably for this type of project the process only required 10 days from first contact to beginning data collection. 

It enabled 16,362 feet of linear electric power assets to be mapped with a median accuracy ± 0.14 feet (4 cm).  Nearly 5,000 photos were captured for future reference. With the web application crew foremen were able to monitor construction progress in real-time to ensure data collection was complete and met their requirements before back filling trenches.  Avoiding the need to coordinate with outside survey crews resulted in a time savings of ~20% in project management for closeouts and reduced time in the field. Overall VPI realized cost savings of ~50% from reduced man-hours.

Conclusion

This remarkable application provides a solution to the decade-old challenge of efficiently capturing high accuracy as-builts in real-time and eliminating the problem of as-built backlogs.  Gas is the most dangerous underground utility and it is not surprising that the development of the Locusview solution was fostered and heavily adopted by the gas distribution industry.  Jurisdictions are beginning to require high accuracy as-builts from energy companies, electric power utilities, water utilities and telecom as a basis for a digital twin. To capture accurate as-builts efficiently is the challenge that Locusview addresses. The VPI case study shows that Locusview is able to provide efficient solutions for capturing accurate as-builts without adding to field crew workload and without impact to project schedules. This solution offers important benefits for any field constructed linear asset.

Mapping gas flowline and gathering system infrastructure mandatory in Colorado

There are nearly a million natural gas and oil wells in the United States, most of which have used fracking to release natural gas and tight oil from underground geological strata.  To gather and collect gas and oil from these wells a vast infrastructure of flowline and gathering has been placed in the ground.  For the most part this has been unregulated and the location of these pipelines is unknown.  The report from the National Transportation Safety Board (NTSB) investigation into the 2017 explosion that killed two people and destroyed a home in Firestone, Colorado determined the likely cause was a natural gas leak through a pipeline that had been severed during construction of the home two years earlier.  The pipeline was a gathering line from an Anadarko well that had been officially abandoned, but the gas valve at the Anadarko well for the line had never been turned off.

When oil and gas operating companies develop new wells they bury flow and gathering lines to collect products from these wells. The lines consist of miles of unregulated pipe for which the operators themselves may not have exact locations, because the lines are generally considered “temporary use” assets. Once a set of wells was depleted, the gathering lines were abandoned, but remained in the ground.

In April 2019, Senate Bill 181 was passed in the Colorado assembly.  It made the Colorado Oil and Gas Conservation Commission (COGCC) responsible for regulating previously unregulated gathering lines.  In response to SB-181 new rules adopted by the COGCC late in 2019 required the oil and gas industry to provide maps of their flowline and gathering system infrastructure.  Much of this infrastructure had never before been documented or identified.

This rule making by COGCC has major implications for oil and gas companies. In 2013, Colorado had 58,200 miles of intrastate gas pipelines of which about 17,300 miles is gas gathering lines.  For comparison Texas, which has the largest pipeline infrastructure in the U.S. with over 450,000 miles of pipeline (about 1/6 of the total pipeline mileage of the entire United States), has over 240,000 miles of gathering lines, most of which is currently unregulated.  In Colorado the COGCC has collected information on about 7,000 miles of flow lines and has published publicly available maps of these flow lines on their website with an accuracy no less than plus or minus 25 feet.

New regulations for pipeline safety creates opportunities for geospatial professionals

New federal regulations in the U.S. will likely more than double the areas where higher levels of pipeline integrity maintenance standards are mandated by federal legislation.  Identifying these areas is more complex creating opportunities for geospatial professionals to apply new technologies including machine learning.

On June 10, 1999, a gasoline pipeline operated by Olympic Pipeline Company exploded in Bellingham, Washington. Three people died in the accident.  On August 19, 2000 a natural gas pipeline owned by the El Paso Corporation exploded near Carlsbad, New Mexico killing 12 people.  After these incidents the government moved quickly to improve the quality of geospatial and other data about underground pipeline assets. The result was within about two years federal regulation from the Pipeline and Hazardous Materials Safety Administration (PHMSA) which required companies operating pipelines carrying hazardous materials to identify high consequence areas (HCAs) where there were 20 or more structures intended for human occupancy within a radius (potential impact radius or PIR) defined by the diameter and pressure of the pipe. Within the HCAs utility companies were required to maintain facilities data at a higher level of integrity. The cost to identify HCAs for a relatively small utility in Pennsylvania that I was familiar with at the time cost $2 million over two years.  This represented a significant opportunity for experienced geospatial professionals.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 mandated telephonic or electronic reporting of accidents and incidents including the amount of product released, number of fatalities and injuries, but not an accurate location, within 48 hours of occurrence.  The act also required the Secretary of Transportation to maintain a map of high-consequence areas in which pipelines are required to meet integrity management program regulations.  At this time the locational accuracy requirement for pipelines was  ± 500 feet.

At the GITA Pipeline Forum in Houston, Darrel Donaho of G2 Integrated Solutions presented an overview of the latest regulations from PHMSA.  Referred to as the Gas Mega Rule the new regulation extends the higher standards of pipeline maintenance to moderate consequence areas (MCAs). Pipeline operators are now required to identify areas where 1) the number of occupied structures within the PIR is five or greater and less than 20 or 2) where any portion of the pipeline PIR intersects the paved area of interstate highways, freeways and expressways and other principal four-lane arterial roads.  They are also required to report longitude/latitude to five decimal places for all incidents.

Whereas in the past identifying HCAs involved hand drawing building footprints from imagery, machine learning can now be used to automate the process of identifying building footprints prior to using a buffer analysis to identify areas qualifying as MCAs.  The analysis is aided by the current accuracy requirement for locating pipelines of ± 50 feet.  Identifying MCAs where highways intersect pipeline PIRs is more complex because automating the identification of transportation corridors is more difficult.  There are alternative, but more expensive ways to find this information.

An analysis of a 14.91 mi transmission line suggests that the impact of the new regulation will be significant, more than doubling the areas where higher integrity maintenance applies.  This creates a significant opportunity for geospatial professionals to apply new technologies including machine learning.

HCA	MCA (>=5)	MCA roads	Total MCA
5.65 mi	2.63 mi	3.03 mi	5.66 mi

 

Carbon dioxide emissions from electric power generation decoupled from economic growth in US

As a rule of thumb increasing electric power generation is closely coupled with economic expansion.  Between 2005 and 2017 the U.S. economy as measured by real GDP expanded by about 20 % from $15 trillion to $18 trillion. New data from the U.S. Energy Information administration (EIA) reveals that over this same period, emissions from power generation dropped primarily because of flat demand which is evidence of a decoupling between economic growth and power generation.

Data from the EIA reveals that during this time US power generation remained flat, but the makeup of U.S. power generation changed significantly.  Generation from natural gas now exceeds that from coal and generation from wind, solar and other renewable sources now exceeds hydroelectric generation.

With respect to emissions the change is even more impressive.  In a business as usual scenario assuming that demand continued to increase as it had prior to 2005, energy intensity (the energy required to produce a dollar of GDP) had remained at its 2005 value, and the energy mix had remained at its 2005 value, the expected emissions from electric power generation would have been about 3,043 MMmt (million metric tonnes). In 2017 actual emissions were much less, about 1,744 MMmt.  About half of the drop in emissions in 2017 compared to the projected business as usual emissions was due to less demand (654 MMmt).  Since the economy expanded over this time this is attributable to a drop in energy intensity and is evidence of decoupling of economic growth from power generation.  The other important factors were switching among fuels, primarily switching from coal to natural gas (329 MMmt) and replacing fossil fuels with non-hydro renewables (316 MMmt). 

In 2017 actual emissions from power generation were 43% less than that projected in the business as usual scenario and 28% below 2005 emissions. This is important progress toward the Paris accord targets (which the U.S. has dropped out of) since emissions from electricity generation are about 28% of U.S. total emissions.

Department of Energy: Increased renewable power generation does not compromise grid reliability

On April 14, 2017 Secretary of Energy Rick Perry issued a memorandum directing preparation of a study to examine whether the retirement of many baseload plants (mostly coal-fired) are premature and whether their retirement reduces grid resilience. The Secretary directed the Department of Energy to conduct a rigorous analysis to answer these questions.  The final report is expected in a few weeks, but a draft has been obtained by Reuters.

Major drivers of retirement: High natural gas availability and low electricity demand

Based on an extensive review of the electric power system evolution and events over the past thirty years and analysis of DOE and other data sources using basic supply and demand principles, a preliminary draft of the study concluded that many baseload retirements are not premature because they are consistent with observed market forces, primarily low natural gas prices and lower than expected electricity demand.   Environmental regulations, state policies and competition with renewables are minor factors that have exacerbated and accelerated these trends. Since 2002 most baseload power plant retirements were victims of over capacity and relatively high operating costs that often reflect the age of the plants. The first tranche of fossil fuel retirements occurred before the explosive growth of renewable generation over the past five years.

Costly environmental regulations and subsidized renewable generation have exacerbated and accelerated baseload plant retirements, but these factors played minor roles compared to the long-standing drop in electricity demand relative to expectations and years of low electricity prices driven by high natural gas availability. While coal and nuclear power used to provide the bulk of U.S. electricity, wholesale electricity prices have closely tracked natural gas prices for the past 15 years beginning about the time that shale gas and oil entered the scene. Low natural gas prices and the fact that new, high efficiency natural gas generation and the pipelines required to provide fuel could be built rapidly helped grow natural gas plants relative to coal and nuclear.  Renewables didn't cause retirements - baseload retirements due to age, inefficiency, and inability to compete began appearing in the early 2000s well before any significant levels of wind and solar generation - but competition with renewables has exacerbated the problem.

Impact on grid reliability

Numerous technical studies for most regions of the nation indicate that significantly higher levels of renewable energy can be integrated without compromising system reliability.                

Region	Minimum level of renewable energy penetration (energy generated, not energy capacity)
New England	24%
PJM (Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia)	30%
Midwest	25%
ERCOT
California	50%
Eastern US	30%
Western US	33% (wind and solar), 40% (all renewables)
Hawaii	100%
National	50%

The study outlines four principal ways to maintain and enhance bulk power system reliability: technology, rules and standards, business practices and last and most expensively, using high levels of transmission and generation.

• Technology advancements now enable wind plants to provide a full spectrum of balancing services. For example, Xcel Energy requires turbines to be on automatic generation control, which allows computerized control system to directly control wind generation output.
• FERC, NERC, and the RTOs and ISOs have undertaken several initiatives to use rules, standards, and grid codes to modify requirements for both interconnectioning renewables and legacy power plants to improve reliability.
• Bonneville Power Administration provides an example of how to integrate wind energy effectively using operational and business practices rather than bringing on more generation reserves. BPA dealt with the reliability risk by limiting the amount of transmission available to the wind fleet (control and curtailment), charging for using hydropower to balance wind generation, and setting a penalty rate to encourage accurate wind generation scheduling.

Do natural gas-fired power plants contribute less greenhouse warming than coal ?

Emissions Associated with Electric Power Production

Methane represents 9.9 % of U.S. greenhouse gas emissions and is at least 20 more times more potent in warming the atmosphere than carbon dioxide.

It has been asserted that natural gas power plants, which are responsible for 21% of power generation in the US, produce 50% less emissions than coal-fired plants. However, in the past the amount of methane gas that is lost (vented or leaked) during production, distribution and in plants has not been included in the calculation. Now a new study suggests that methane emissions from power plants and refineries may be much larger than current estimates.

A recent EPA analysis doubled its previous estimates for the amount of methane gas that leaks from pipes and is vented from gas wells, which significantly changes the emissions picture.  Methane (CH₄) levels from hydraulic fracturing of shale gas were found to be 9,000 times higher than previously reported.  Based on the new numbers, the median gas-powered plant in the United States is estimated to be 40 % cleaner than coal-fired plants, according to calculations ProPublica has made. In addition about half of the 1,600 gas-fired power plants in the US operate relatively inefficiently. In the past these plants were estimated to be 32 % cleaner than coal, but with the revised EPA estimates, these ~800 inefficient plants are estimated to produce 25 percent less emissions than coal.

But there is another issue.  Methane is one of the more potent greenhouse gases for global warming, but it is not clear just how much more potent methane is than CO₂.  The EPA has estimated a factor of  21 times compared to carbon dioxide. But Robert Howarth, an environmental biology professor at Cornell University, has suggested that it is actually 72 times as powerful as carbon dioxide in terms of its warming potential.  This is critical, because if the climate effect of methane from natural gas is 72 rather than 21 times that of carbon dioxide from burning coal, natural gas may even turn out to be worse than coal in terms of global warming.  Howarth has suggested that the type of shale gas drilling taking place in Texas, New York and Pennsylvania generates particularly high emissions of methane and could be as dirty as coal.

New estimates of methane emissions from power plants

Now a new study reports on overflights of power plants and refineries and finds that methane emissions are much larger than current estimates.  Power plants and oil refineries are large consumers of natural gas. The EPA has collected data contributed by operators and estimated the methane (CH4) emissions from these plants, but there is high uncertainty in these estimated. In this study an airborne chemistry lab was used to estimate the methane emissions from three gas-fired power plants and three oil refineries. The average methane emission rates were larger than than the operator-reported estimates by 21 to 120 times for the power plants and by 11 to 90 times for the refineries. By looking at the pattern of methane emissions compared to carbon dioxide (CO2) and water vapour, the researchers were able to determine that the methane emissions were primarily from non-combustion processes suggesting leaks and venting as the sources. Scaling these result to the national level suggests that methane emissions from these types of facilities are 4.4 to 42 times larger than current estimates. The results indicate that gas-fired power plants and oil refineries could contribute significantly to U.S. methane emissions. The estimated contribution of 0.61 teragrams of methane annually (Tg CH4/yr) is significant, representing about 2% of total U.S. annual emissions of methane of about 30 Tg CH4/yr.

A recently published study has assessed the spatial distribution of anthropogenic methane sources in the United States by combining comprehensive atmospheric methane observations, extensive spatial datasets, and a high-resolution atmospheric transport model. Based on the results of this analysis the authors conclude that the EPA underestimates methane emissions nationally by a factor of about 1.5.  Generally the study found that methane emissions due to the animal husbandry and fossil fuel industries have larger greenhouse gas impacts than indicated by existing inventories.

One of the motivations from switching from coal to natural gas for these types of facilities is that natural gas delivers the same amount of energy but with significantly reduced emissions. But that does not take into account leaks and other processes releasing methane during production, distribution and within plants.  These latest results further reduce the advantage of gas-fired over coal-fired power production.

A study by Robert W. Howarth, Renee Santoro, and Anthony Ingraffea has concluded that the emissions of methane from shale gas wells are between 30% and 100% more than methane emissions from conventional natural gas wells.  The study estimates that between 3.6% to 7.9% of the methane from shale-gas production escapes to the atmosphere in venting and leaks over the lifetime of a well.

As a result the study found that the greenhouse gas (GHG) footprint for shale gas is greater than that for conventional gas or oil. When compared to coal, which is responsible for nearly 50% of electric power generation in the US,  the GHG footprint of shale gas is estimated to be 20% to 100% greater than coal over a 20 year period.  Over a 100 years, the study concludes that the GHG impact of shale gas is comparable to coal.

IEA World Energy Outlook projects world warming greater than 2° C based on COP21 committments

The International Energy Agency (IEA) has issued its annual World Energy Outlook 2016.  The IEA has examined several scenarios. All the Paris COP21 climate pledges from 190 countries have been incorporated into its main scenario.  (It does not include any assessment of what the Trump administration may do with respect to the COP21 committments made by the world's second largest emitter.) It has projected that this scenario will actually result in 2.7 °C of warming.  A scenario, called the 450 Scenario, with a 50% probability of limiting global warming to 2 ° C was also examined.

In its main scenario which includes emission reductions from COP21 pledges, the IEA projects a 30% rise in global energy demand to 2040.  In 2040 it is projected that 60% of all new power generation capacity will come from renewables.  In 2040 renewables are projected to represent 37% of all power generation.  By 2040 most renewables-based generation is projected to be competitive without subsidies. Solar PV is expected to see a further 40-70% reduction in cost by 2040 and onshore wind by an additional 10-25%. However, fossil fuel generation continues to be important. Natural gas consumption is projected to rise by 50%.  Growth in coal use essentially stops while growth in nuclearpower is limited to China.

Energy-related CO2 emissions plateaued in 2015 mainly because of a 1.8% improvement in the energy intensity of the global economy.   This is partly because a growing proportion of the $1.8 trillion currently invested in energy annually is directed to renewables.  But the IEA projects that even with the COP21 commitments energy-related emissions will continue to grow by 0.5% per year.

It is projected that a cumulative $44 trillion in investment will be needed in the global energy supply over the next 15 years.  60% of this will go to oil, gas and coal extraction and supply, including power plants using these fuels, and nearly 20% to renewable energies. Another $23 trillion will be required for energy efficiency improvements.   For comparison over the last 15 years, 70% of total energy supply investment went to fossil fuels.   This scenario requires a significant reallocation of capital from fossil fuels to renewables. This is aided by dropping fossil fuel subsidies.  In 2015 the value of fossil-fuel consumption subsidies dropped to $325 billion, down from $500 billion the previous year.

The IEA projects that the COP21 commitments will slow the projected rise in global energy-related CO2 emissions.  However, it does not believe that this is enough to limit warming to less than 2 °C.  The IEA's 450 Scenario, which is based on a 50 % probability of limiting warming to under 2 °C, requires a further major reallocation of investment capital going to the energy sector. A greater proportion of the $40 trillion in cumulative energy supply investment has to move from fossil fuels and towards renewables and other low carbon investments in nuclear and carbon capture and storage so that the share going to fossil fuels would drop to about a third. In addition, $35 trillion is needed for improvements in energy efficiency - that's $12 trillion more compared with the main scenario. The 450 Scenario implies that before the end of this century, the energy sector must become carbon-neutral.  That means all residual emissions from fuel combustion are either captured and stored, or offset by technologies that remove carbon from the atmosphere.