Between the Poles

Faster and safer mapping underground infrastructure using magnetometers mounted on a drone

Technologies such as ground penetrating radar (GPR) or acoustic locating for detecting underground utilities involve directing some type of signal, electromagnetic or acoustic, into the ground and measuring the reflection off underground objects. A major challenge for these techniques is attenuation which limits the depth of penetration of the signal. For example, wet soils such as clays can render ground penetrating radar ineffective.  Technologies for remotely detecting underground objects that are not susceptible to attenuation include gravimetry and magnetometry.  I recently blogged about increased sensitivity of gravimetric equipment using quantum effects, an approach that has shown promising results in academic experiments. However, collecting data is still relatively slow and requires "boots on the pavement" which always raises safety issues. Now a novel approach using magnetometry allows centimetre-accurate locations to be measured for underground metallic pipe networks.  Even more importantly, a device combining magnetometers and accurate GNSS is light enough to be mounted on a UAV or drone, which provides much faster and safer data acquisition.

In 2012 a French government’s decree (DT-DICT) mandated that energy network operators accurately map their energy (oil and gas) pipeline networks by 2026.  This decree has motivated French energy companies to assess different alternatives for locating and mapping their underground assets.   SKIPPER NDT was started in 2016 based on the concept of leveraging the physical principles of magnetism to perform contactless measurements on pipelines with the objective to improve operational safety and rationalizing operational expenditure. Their latest development involved mounting on a drone all the necessary equipment to perform a high precision magnetometric measure to detect underground pipelines. SKIPPER NDT has partnered with Total, GRTgaz, Teréga and other major French energy network operators to demonstrate the performance of their technology in real conditions. The French National Centre for Scientific Research (CNRS) has also provided an objective scientific validation of their approach. Recently I had the opportunity to speak with Luigi Kassir, Co-founder and COO of SKIPPER NDT.

The disadvantage of a remote detecting device such as GPR that has to be wheeled at a walking pace, typically in a grid pattern covering the area of interest is that it requires "boots on the pavement" which is often dangerous especially in active traffic.  Towing a rig at highway speeds as in the case of recent ground penetrating equipment is one way to speed up data acquisition and avoid boots on the pavement.  However, attenuation is still a problem and adverse soil conditions can render GPR ineffective. As an alternative SKIPPER NDT has developed a device that integrates several magnetometers and accurate GNSS geolocating equipment which is light enough to be loaded on a UAV or drone.  The advantage of this approach is that it is unaffected by soil conditions, dramatically speeds up data acquisition and avoids the safety issues associated with ground-based equipment.

Magnetometry involves detecting and measuring the magnetic field emitted by underground conducting objects.  To enhance the magnetic signal emitted by a metallic pipe an electric signal generator can be used to inject an electromagnetic signal. The SKIPPER NDT device consists of a proprietary electronic logic card, five 3-axis fluxgate magnetic sensors, a topographic GNSS+RTK capacity as well as a high-precision inertial unit. Magnetic field strength readings, measured in nanoteslas (nT), are recorded continuously by the SKIPPER NDT device and are used to compute the location of the pipe (XYZ) and its depth of cover. A suite of algorithms has been developed to interpret the magnetic field strength measurements under various conditions, for example, overcoming external electromagnetic interference along the pipeline route, such as power poles.

Most importantly the device weighs only 2.5 kg, making it light enough to be mounted on a UAV or drone. The success of Skipper NDT's drone mounted technology has been scientifically demonstrated and validated under live field conditions. SKIPPER NDT’s performances were validated in the field with the French pipeline operator Teréga. Surveyors contracted by Teréga geolocated two pipelines with diameters of 6’’ and 8’’ in an open ditch. The ditches were then backfilled.  In a blind test  the SKIPPER NDT team was invited to detect and map the pipelines using hteir drone-based device. Using their drone mounted system the SKIPPER NDT team was able to capture magnetic field readings over 482 feet in just 6 minutes. It was found that the average precision of detection of the underground pipeline was 6.1 inches.

Furthermore, because SKIPPER NDT’s records continuous measurement along the pipeline, it can precisely map bends and elbows. It can also detect metallic objects and structures near the pipeline including other metallic utilities. For example, during one of the field tests, SKIPPER NDT was able to identify another pipeline whose presence had not been previously reported but which crossed the target pipeline.

There are limitations to the effectiveness of magnetometry.  External magnetic noise can be a problem.  Sources of magnetic noise that are prevalent in urban environments can drown out the target signal and complicate detection of underground pipelines.  For this reason, the technology is most effective in rural and semi-rural areas.

In summary the advantage of the SKIPPER NDT drone-mounted device is that it provides fast, safe, and centimetre-accurate data acquisition. Its automated data acquisition and processing tools mean results can be delivered faster than conventional methods making the solution also rapid and cost-efficient.

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.

Nanosatellites and drones represent a paradigm shift in measurement of methane emissions

Annual emissions of methane (CH4) have risen by almost 10% in the past two decades. The primary sources of methane are the oil and gas industry and agriculture, in large part from livestock.  Methane emissions are either measured on the ground, a slow, laborious process using a hand-held scanner or over a broad area using government-funded aircraft overflights or satellites.   But this is changing. In 2016 a privately-funded startup GHGSat launched a cubesat weighing 15 kg with 50 metre resolution to measure methane emissions from individual oil and gas wells, refineries, compressor stations, landfills, animal feedlots, rice paddies, and natural sources.

Background

Source Nature 14 July 2020

Annual emissions of methane have risen by almost 10% in the past two decades. Atmospheric concentrations of methane reached1,875 parts per billion in 2019 which is more than 2.5 times above pre-industrial levels.  The primary anthropogenic sources of methane are the oil and gas industry and agriculture, especially livestock production (enteric fermentation).

A study used spatial analysis to investigate 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 US Environmental Protection Agency (EPA) underestimates methane emissions nationally by 50%.  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.

A study by Robert W. Howarth, Renee Santoro, and Anthony Ingraffea 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 estimated 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.  The study suggested that the leakages are sufficiently large to erase the advantage of natural gas over coal in producing energy with lower emissions.

Another source of methane in the atmosphere are leaks from natural gas distribution systems.  A partnership between the Environmental Defense Fund (EDF) and Google Earth released interactive maps showing methane leaks from gas distribution systems under the streets of Boston, Indianapolis and part of New York City.

In 2016 the Obama administration issues new rules regulating methane emissions from the oil and gas industry and requiring the monitoring and reporting of emissions.

The U.S. Environmental Protection Agency (EPA) has estimated U.S. emissions taking a bottom-up approach in which emissions from individual facilities are aggregated.  Other sources have used top-down measurements from aircraft overflights and satellites funded by government agencies.  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.

Measuring methane emissions

Measurements of oil and gas CH4 emissions are either captured by top-down (TD) or bottom-up (BU) collection methods. Top-down measurement of methane use aircraft and satellites and estimate emissions from many sources across large geographies. These are generally government funded.  Bottom-up studies measure emissions from individual pieces of equipment, operations, or facilities on site or directly downwind and can be industry funded, government funded or funded by a not-for-profit such as the EDF. Currently the way to scan an oil or gas field for methane emissions is visiting each facility and pointing a handheld device at the facility and looking for a telltale wisp indicating a methane leak. For an oil and gas field this can take weeks.  New technologies including nanosats and drones are radically changing how methane emissions are measured.

GHGSat

In 2016 a venture capital funded startup GHGSat based in Montreal launched a demonstration cubesat weighing 15 kg and named Clair.  The objective was to provide satellite-based methane measuring device that would enable private industry to estimate emissions from its own facilities anywhere in the world. An 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.

Claire orbits the Earth every 90 minutes. Its field of view is roughly 12 km x 12 km and it has spatial resolution of less than 50 metres. Claire is able to measure emissions from over 1,000 sites per year. 

The next two satellites (GHGSat-C1, or "Iris" and GHGSat-C2, or "Hugo") are scheduled for launch in 2020.  Iris, scheduled to launch in the middle of August, will have higher resolution (25 metres) than Claire and will be able to measure emissions much more rapidly.

Drones

In a recent Microdrones webinar, Bret Burghdurf described how drones are being used to measure methane emissions from 30 to 80 feet up in the air.  Capturing methane emissions using a methane detector carried by a drone is generally reliable, the only areas where it may not be are over standing water and deep snow.  The drone carries a camera in addition to the methane sensor allowing the facilities being monitored to be captured visually.  The device is capable of capturing 10 readings per second.  Typically over a facility such as a chemical plant, tank farm, compressor station or landfill a grid pattern is flown. Over a linear asset such as a pipeline the flight plan follows the pipeline.  The market for this type of measuring is typically the oil and gas industry itself.

Sentinel 5p TROPOMI

The European Space Agency (ESA) launched the Copernicus Sentinel 5 Precursor (5p) with the TROPOMI sensor onboard in 2017.  It can capture regional emissions of methane, nitrogen dioxide, sulfur dioxide and other gases and aerosols for the entire earth every day. Sentinel 5p weighs about 900 kg and captures a swath width of 2,600 km with a pixel size of 7 km x 7 km.

MethaneSAT

Intended to launch in 2023 MethaneSAT will cover a 200-kilometer view path with a revisit time of every few days. The satellite weighs 350 kg and has a resolution of 100 m x 400 m across a 260 km swath. MethaneSAT is being developed by a subsidiary of the non-profit Environmental Defense Fund (EDF).

Conclusion

Methane is a greenhouse gas whose concentration in the atmosphere is rapidly increasing.  The source of most of this increase is anthropogenic and being able to efficiently measure and monitor methane emissions is going to be critical in controlling and reducing emissions.  New technologies from privately funded companies and others including nanosat- and drone-based methane sensors are providing more efficient and higher resolution devices for measuring methane emissions from many different sources in the fossil fuel industry and agriculture.

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.

Excavation damage remains a leading cause of serious pipeline accidents

Pipeline incidents (gas distribution, gas transmission, gas gathering and hazardous liquid) resulting from excavation damage 2005-2019

Gas and hazardous pipeline operators are required to report all pipeline incidents to Pipeline and Hazardous Materials Safety Administration (PHMSA) including location, volume of product released, number of fatalities and injuries, costs and cause.  Since 2005, pipeline operators have reported excavation damage as the cause of 1052 incidents, resulting in 48 fatalities, 195 injuries requiring hospitalization, and $ 481,736,551 of property damage.

Gas distribution leaks by cause 2018 PHMSA

Since 2004 the total miles of pipeline in the US including crude oil lines, petroleum product lines, gas distribution mains, gas transmission pipelines, and gas gathering lines increased by about 12 % to 1,830,672 miles in 2017.  Pipeline operators are required to submit performance measure reports to PHMSA for pipeline infrastructure covered by integrity management (IM) programs. This includes gas distribution, gas transmission, and hazardous liquids.

Pipeline operators are required to report all pipeline damage and leak incidents to PHMSA.  Failure to do so can result in a fine.  The leading causes of pipeline incidents are corrosion, excavation, and incorrect operation of equipment.

PHMSA has devoted significant effort to reducing damage during excavation. In some states certain type of excavators are exempt from calling one-call centres. In Texas, which is the state with the most miles of natural gas pipelines and the most accidents, exempt groups include gravediggers, railroad maintenance crews, oil and gas drillers, farmers, and county and state road crews.  A 2014 PHMSA report A Study on the Impact of Excavation Damage on Pipeline Safety found that its analysis suggested that exemptions for property owners from calling the one-call notification system, especially when coupled with exemptions for hand tools, can lead to higher percentages of damages.  For the States that were analyzed, the analysis indicated that the damage rates for States with five or more notification exemptions is 108 percent greater than the rate for States with fewer than five notification exemptions. A similar analysis, performed by the United States Infrastructure Corporation (USIC) and based on information gathered during USIC’s investigations of over 100,000 damages, also found that larger numbers of exemptions from State one-call laws coincided with increased damage rates.  PHMSA has stated that it believes that State one-call damage prevention laws should apply to all excavators, that no entities should be exempt from the one-call notification process.

The 2017 PHMSA report entitled A Study on Improving Damage Prevention Technology found that despite efforts by PHMSA and other stakeholder groups, including pipeline operators, excavators, and trade associations such as the Common Ground Alliance, to improve the practices and technologies, excavation damage remains one of the leading causes of serious pipeline accidents.  It made several recommendations, among them are improving and implementing GPS/GIS technologies in accurately locating and documenting the location of underground facilities, national standards for state one-call requirements and evaluating and implementing predictive analytic tools,which use data to identify and proactively address high-risk excavations.

Reliable statistics provide a foundation for improving pipeline safety

Pipeline incidents (gas distribution, gas transmission, gas gathering and hazardous liquid) resulting from excavation damage 2005-2019

“If you can’t measure it, you can’t improve it.” (Peter Drucker) is a maxim that applies to airline accidents, gas and oil pipeline explosions and leaks and underground utility damage resulting from excavation.  Whereas reliable statistics have been available for the civil aviation industry since the early 20th Century, for gas and hazardous liquids pipelines reliable statistics have only been available since the beginning of the 21st Century.

Aviation safety: fatalities per trillion passenger kilometres 1970-2018

Reliable metrics provide a foundation for assessing the social and economic impact of incidents and the effectiveness of new technologies and policies in preventing and reducing the severity of these incidents. The commercial airline industry is a model of what reliable statistics and data for incidents and policies and technologies designed to reduce these incidents can achieve.  In the civil aviation industry there have been reliable statistics since the early 20th Century. The Air Commerce Act of 1926 created an Aeronautic Branch of the United States Department of Commerce. In 1929 there were 51 commercial airline incidents, which represents an accident rate of about 1 for every 1,000,000 passenger miles. If that rate is prorated to the current total number of revenue passenger miles this would be equivalent to 7,000 fatal incidents per year. Fatal accidents per million flights in 2018 have decreased 16 fold since 1970, from 6.35 to 0.39, and fatalities per trillion revenue passenger kilometers (RPK) decreased 54 fold from 3,218 to 59 in 2018. 

Since 2004 the total miles of pipeline in the US including crude oil lines, petroleum product lines, gas distribution mains, gas transmission pipelines, and gas gathering lines increased by about 12 % to 1,830,672 miles in 2017.  The Pipeline and Hazardous Materials Safety Administration (PHMSA) was created in 2004 by federal legislation.  Pipeline operators are required to submit performance measure reports for pipeline infrastructure covered by integrity management (IM) programs. This includes gas distribution, gas transmission, and hazardous liquids.  Operators are required to report all pipeline incidents including the amount of location, volume of product released, number of fatalities and injuries, costs and cause.  Since 2005, pipeline operators have reported excavation damage as the cause of 1052 incidents, resulting in 48 fatalities, 195 injuries requiring hospitalization, and $ 481,736,551 of property damage.

Gas distribution leaks by cause 2018 PHMSA

Possible causes include

• CORROSION - caused by galvanic, atmospheric, stray current, microbiological, or other corrosive action.
• EXCAVATION DAMAGE - incidents resulting directly from excavation damage by operator's personnel, by the operator's contractor, or by people or contractors not associated with the operator
• INCORRECT OPERATION - incidents caused by operating, maintenance, repair, or other errors by facility personnel
• MATERIAL/WELD/EQUIP FAILURE - incidents resulting from poor welds, poor construction, and stresses such as vibration, fatigue, and environmental cracking.
• NATURAL FORCE DAMAGE - incidents resulting from earth movement, lightning, floods and washouts, frost heave, and other natural causes.
• OTHER OUTSIDE FORCE DAMAGE - incidents caused by non-excavation-related outside forces including vandalism and terrorism.
• ALL OTHER CAUSES -  incidents whose cause is currently unknown

Gas distribution leaks by cause 2010 PHMSA

Since pipeline incident data began to be collected the proportion of incidents attributed to excavation has increased.  For example in 2018 34.4 % of gas distribution leaks (unintentional escapes of gas from the pipeline not reportable as Incidents) were caused by incorrect operation.  In 2010 only 16.4 % were attributed to incorrect operation.  Clearly improved training and other initiatives have reduced equipment operation failures but also being able to better identify causes has made it possible to reduce other types.

Serious pipeline incidents, fatalities, and injuries 1999-2018 PHMSA

Serious Incidents include a fatality or injury requiring in-patient hospitalization.  PHMSA statistics suggest there may have been some improvement in number of serious incidents and in fatalities, but prorating these statistics to pipeline mileage suggests otherwise.

Significant gas transmission pipeline incidents per 10 000 HCA miles 2004-2018

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. Operators were required 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. 

One of the reported statistics is the number of significant incidents per 10,000 HCA miles.  Significant incidents are defined as incidents involving a fatality or injury requiring hospitalization, $50,000 or more in total costs measured in 1984 dollars, substantial liquid releases, or fires and explosions.  The data reveals no trend in improvement in this statistic.

By analogy with the civil aviation industry, reliable statistics resulting from government mandated reporting of pipeline incidents provides the foundation for the next phase of implementing safety management plans designed to produce continuous improvement in these statistics. Safety management systems tailored to specific industries and requirements have been developed often involving regulation for civil aviation, international maritime shipping, and the rail industry in Canada.  At the GITA Pipeline Forum in Houston, there was a lot of discussion about pipeline safety management systems (PSMS), specifically the RP 1173 framework developed by the American Petroleum Institute (API) in partnership with PHMSA, state pipeline regulators, and other interested stakeholders. RP 1173 provides best practices for pipeline operators including operational controls, risk management, incident investigation, evaluation, and lessons learned, and safety assurance.  This is intended for operators of hazardous liquids and gas pipelines under the jurisdiction of the US Department of Transportation.  It provides for the comprehensive and systematic management of safety-related activities for achieving its goal of zero incidents per year.

Tracy Thorleifson of G2 Integrated Solutions suggested that at this stage we should be really worrying about asset integrity risk assessment.  Pipelines are distinguished from airplanes in being in intimate contact with their environment which means many more variables to consider.  Pipeline operators routinely capture and store operational information about their networks including pressure, flow rates, valve status and so on, but they don't capture and store information about the environment in which the pipeline is operating, such as, earth movement including subsidence, soil types, landuse, vegetation, proximity to water bodies, etc.  Asset integrity assessment should include real-time dynamic segmentation using the thousands of data layers for the external environment available from NOAA, NASA, ESRI Living Atlas and other sources.  This is an area where machine learning could fruitfully be applied to calculate risks of external events affecting the integrity of pipelines.  For a pipeline in an area prone to flooding,  subsidence, land slide, or river bank collapse, using dynamic segmentation would permit using these factors to adjust the risk assessment algorithms. Furthermore risk models should include data quality, including location accuracy, as a potential threat factor.  For example, not knowing accurately the proximity of hazardous underground utilities can seriously compromise risk assessments.

In summary since 2005 the gas and oil pipeline industry and its regulator have achieved reliable statistics for pipeline incidents.  The focus is now on regulation, policies and technologies to improve these statistics to reduce the number and severity of pipeline incidents.

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

 

Towards a digital twin of infrastructure: efficient reality capture of new pipelines

Traditionally when a new pipeline is put in the ground, either its location and depth is only approximately known or it has to be surveyed by a registered surveyor.  Now there is another alternative. At GeoAlberta 2018 is Edmonton Joseph Hlady of Lux Modus described how his company has developed a rig and software running in the cloud that allows this information to be captured in "near real-time" as the pipeline is constructed.  The rig includes LiDAR and photo cameras which capture the trench and the pipeline by driving along each section before the trench is filled to record a point cloud and photos.  The point cloud and images are uploaded for cloud processing and within minutes to hours a digital twin of the pipeline can be viewed by anyone with a browser that supports HTML5 including mobile devices.

By automatically detecting the top of the ditch and the top of the pipe, the location (x,y) and depth (z) of the pipe can be computed in real-time by the LuxGear or later in a GIS.  Lux Modus uses the Unity gaming engine to enable 3D walk-throughs in virtual reality (VR) of the pipeline after the ditch has been covered.  For example, this makes it possible for QA/QC people to use VR to identify weld points in the office rather than in the field.

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.

Global methane emissions 60 to 110 % greater than current estimates

Methane has the second-largest global radiative forcing impact of anthropogenic greenhouse gases after carbon dioxide. In addition to anthropogenic sources, mainly fossil fuels, livestock and waste, natural methane sources include the biosphere (wetlands, termites, oceans, wildfires, and wild animals), volcanoes and geothermal emissions, and geological seepage where large quantities of natural gas migrate from shallow or deep rocks and reservoirs to the surface along faults and fractured rocks.

Estimates of emissions have come under increasing scrutiny. A recent study 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. It was concluded that the US Environmental Protection Agency (EPA) underestimates methane emissions nationally by a factor of 1.5.

The concentration of methane in the atmosphere stabilized from about 1999 to 2007.  But here is evidence that since 2007 it began rising again.  A recent study suggests that the more than 30% increase in U.S. methane emissions over the 2002–2014 period could account for 30–60% of the global growth of atmospheric methane seen in the past decade.

In a study just published the global methane budget and the contribution of the fossil fuel industry to methane emissions has been reevaluated. The ratio of carbon-13 to carbon-12 provides a signature which helps identify the source of methane. Both global methane and methane carbon isotope (carbon-13) records were used to compile what is believed to be the largest isotopic methane source signature database, including fossil fuel, microbial and biomass-burning methane emission sources. Total fossil fuel methane emissions from the fossil fuel industry plus natural geological seepage are 60 to 110 % greater than current estimates. After accounting for natural geological seepage, it is found that methane emissions from natural gas, oil and coal production and their usage are 20 to 60 % greater than current estimates.