NWGA & PNUCC Examine Future Gas Infrastructure Development in New Whitepaper

Portland, Ore. —The Northwest Power & Natural Gas Planning Taskforce released Northwest Gas Infrastructure – Looking Forward this week.  The report provides a glimpse into the Pacific Northwest’s potential future natural gas infrastructure, and why the gas infrastructure system may change.

Utilities and other users rely on the infrastructure system, a network of pipelines and storage facilities, to deliver natural gas from supply basins to the point of consumption.  The existing system has reliably heated homes, run power plants and fueled industrial processes in the Northwest for decades.  Today, the system is still sufficient to meet the region’s needs but runs close to its limit during severe cold weather events.

Looking forward, in part due to abundant, affordable gas supplies and existing infrastructure, new gas users are thinking of moving into the region.  As these new users come to the Northwest they will add additional demand to a system that is already nearing capacity.  Serving these new users may require additional gas infrastructure.

If the gas infrastructure system is expanded, it will likely be new users, not utilities, driving the expansion. Utilities may need to change their preferred gas supply strategy and transportation products based on changing system dynamics introduced by new infrastructure developments.

The Taskforce is a joint effort of the Northwest Gas Association and PNUCC.  The Taskforce’s members largely consist of natural gas utilities, pipelines, electric utilities that consume gas to generate power and industrial user representatives.

Electronic copies of the full report are available at:



Natural Gas Infrastructure Looking Forward

Click Here To Download Our White-paper:
“The Northwest Gas Landscape – Looking Forward”

The Northwest depends on natural gas for producing electricity, heating homes and businesses, and powering industrial processes.  Unlike some fuels, gas is difficult to store on-site.  Both electric and natural gas utilities rely on the gas infrastructure system, a combination of pipelines and central storage facilities, to deliver gas the moment it is needed.

Potential new gas user comparison by consumption

Potential new gas user comparison by consumption

The size of the infrastructure system, and the type of arrangements utilities need to ensure a reliable gas supply, are dependent on regional supply and demand trends.  This report discusses these trends, what new infrastructure options may be available, potential new gas users in the Northwest, and how these factors impact utility gas supply planning.

For the purpose of this report, “utility” refers both to natural gas distribution utilities and electric utilities that generate electricity using natural gas.  Additionally, the Northwest market area is defined as British Columbia, Idaho, Oregon and Washington.  Some gas used in the Northwest flows from Alberta and the U.S. Rockies; although these areas are not discussed in this report, they do impact Northwest gas supplies.  Lastly, a “large” new user as discussed in this report is defined as consuming more than 150,000 dekatherms of gas per day (Dth/day).


Key Report Takeaways:

  • Large new gas users could have more control over future infrastructure expansions than existing users, including utilities.  Utilities may have to adapt their preferred gas supply and infrastructure strategies based on the location and timing of infrastructure projects chosen by large new gas users.
  • Utilities need reliable pipeline transportation from a robust gas supply.  As new users enter the region, and existing users change their gas consumption patterns, what is considered to be a robust supply may change.  This could cause utilities to change their preferred gas supply portfolio and/or transportation product (firm or non-firm) needed to ensure reliable delivery of gas to the point of consumption.


Click Here To Download Our White-paper:
“The Northwest Gas Landscape – Looking Forward”

Key Takeaways from the CSU Methane Emissions Study

Last week Colorado State University released the results of an in-depth study of methane emissions from natural gas transmission and storage facilities. The study is another in a series performed by academic institutions and the Environmental Defense Fund (EDF) seeking to gain a better idea of the scale of methane emissions from natural gas infrastructure.

Some of you may remember our discussion of the LDC edition of this study, performed by Washington State University researchers, on our May webinar.

Much like previous studies Colorado State’s research indicated that actual methane emissions from pipelines and storage facilities are far lower than EPA estimates, 27% lower on average across the nation. Why does this matter? Don Santa, President of the Interstate Natural Gas Association of America (INGAA) broke it down in a recent blog:

 “This finding is important. It underscores why the EPA needs to update the emissions factors it uses to estimate its inventory to reflect more accurately how the transmission and storage sector operates today.  EPA largely relies on data from a nearly 20-year-old study to calculate its greenhouse gas inventory. While EPA has appropriately updated emission factors and estimation methods in select cases for other industry sources, including wells in the exploration and production sector, it has not for transmission and storage sector sources.”

Click here to read Don Santa’s blog, where he breaks down some of the other key takeaways from the study.

Colorado State University researchers present results of comprehensive study of methane emissions from natural gas transmission and storage facilities

FORT COLLINS — A comprehensive study of natural gas transmission and storage facilities led by Colorado State University (CSU) researchers has found that the total amount of methane emitted into the atmosphere from the transmission and storage sector is not statistically different from the emissions from the transmission and storage sector reported in the Environmental Protection Agency’s 2012 Greenhouse Gas Inventory.

The study, published today in the journal Environmental Science & Technology, found overall methane emissions from transmission and storage facilities ranging between 1,220 and 1,950 Gigagrams/year (mean of 1,503 Gg/yr.). The EPA’s Greenhouse Gas Inventory (GHGI), one of the federal agency’s two programs that track methane from the natural gas system, estimated emissions between 1,680 to 2,690 Gg/yr (mean of 2,071 Gg/yr). Because these ranges overlap, the researchers consider the two estimates statistically similar.

The study estimates that total methane emissions from the transmission and storage sector resulted in the loss of 0.28% to 0.45% (mean of 0.35%) of the methane transported in 2012.

The paper is the final analysis of one of the most comprehensive studies of methane emissions from natural gas transmission and storage facilities. It is part of the largest on-site measurement campaign of the U.S. natural gas infrastructure to date.

For the study, researchers from CSU, Carnegie Mellon University and Aerodyne Research, with support from seven natural gas pipeline companies, measured amounts of methane emitted from compressor stations and storage facilities on large natural gas transmission pipelines across the country.

The primary component of natural gas, methane is a greenhouse gas many times more potent than carbon dioxide when released into the atmosphere unburned. The nation’s vast natural gas infrastructure – including wells, pipelines, and storage facilities – is one of many sources of methane emissions in the United States.

The CSU study provides much-needed information on emissions in the U.S. pipeline transmission and storage sector, which includes roughly 1,800 compressor stations and underground storage facilities positioned along approximately 300,000 miles of pressurized natural gas transmission pipelines. The partner company transmission facilities represent approximately 56 percent of the interstate transmission facilities in the U.S.

The research team used 2,292 new on-site measurements and equipment data from 922 facilities to build a computer model to calculate overall emissions.

Based on the results of the study, the authors estimate that approximately one in 25 facilities may be emitting 300 standard cubic feet per minute or more of natural gas at any given time. These emissions account for about one-third of fugitive emissions — unintended emissions from equipment in the pipeline transmission and storage sector — and a quarter of all methane emissions from the sector annually.

“Our data indicate that these releases are both intermittent and unpredictable,” said Daniel Zimmerle, senior research scientist at the CSU Energy Institute, who led the study.

The study also found that fugitive emissions account for 75 percent of all methane emissions in the transmission and storage sectors. Half of these emissions are from major compressor equipment such as seal vents, unit isolation and blow-down valves and rod-packing vents.

Researchers also found that the equipment used in this sector is significantly different than assumed in previous estimates, which can greatly affect the amount of methane being emitted. For example, companies have replaced many smaller engine-driven reciprocating compressors with larger and fewer centrifugal compressors resulting in less unburned methane in exhaust gases.

As part of the study, researchers also compared methane emissions in this sector to the EPA’s Greenhouse Gas Reporting Program (GHGRP). The GHGRP requires reporting of emissions from facilities with annual greenhouse gas emissions greater than 25,000 metric ton carbon dioxide equivalent. The new model indicates facilities that report to the program emit 2.6 times more methane than reported to the EPA.

Zimmerle noted that the difference can be attributed to a combination of factors inherent in the reporting requirements. Factors include emission estimation methods, measurement methods and emissions sources that are not required to be reported under the federal program.

The study was sponsored by the Environmental Defense Fund and supported by Dominion, Dow Chemical, Enable Gas Transmission, Kinder Morgan, Columbia Pipeline Group, TransCanada and The Williams Companies. The Interstate Natural Gas Association of America also participated in the study.

The Colorado State University study is one of 16 organized by the Environmental Defense Fund and industry partners to better quantify the amount of methane released into the atmosphere from the natural gas supply chain. This is the second paper published by researchers at CSU and Carnegie Mellon as part of the project.

The full paper can be found at pubs.acs.org/doi/abs/10.1021/acs.est.5b01669

More information about the study can be found at www.edf.orgingaa.org, andenergyinstitute.colostate.edu/p/transmission-and-storage.html


Why ‘pigs’ in PSE’s gas pipes are a good thing

PSE recently completed an in-line inspection of the Sumas natural gas pipeline using a series of devices called “pigs.” The pipeline, located near the Canadian border, is an 8-inch, 3.7 mile transmission line that serves the Sumas Cogeneration Plant. The maintenance is part of the Transmission Integrity Management Program.

The work happened over the course of three days in May. On the first day, crews flared off the natural gas in the pipeline, which is a controlled burn, in preparation for the inspection. The following day, crews inserted two foam devices called “pigs” into the pipeline and propelled them with nitrogen.

The foam pigs are often used first since they are relatively inexpensive and serve as a test run for the other tools without damaging the pipe.  Afterward, the remaining tools were launched with compressed air. That was one of the most complicated decisions: choosing the best way to propel the inspection tools, with nitrogen and compressed air being the best options.

Up next, a brush pig was sent down the line to clean the pipe, and a caliper pig was then launched to determine if there were any large deformations in the pipe that could impede the progress or damage the more expensive “intelligent pigs.”

The “intelligent pigs” included a geometry tool, which is most often used for detecting damage to the pipeline involving deformation of the pipe cross section.  The deformation can be caused by construction damage, dents caused by the pipe settling onto rocks, third-party damage, and wrinkles or buckles caused by compressive loading or uneven settlement of the pipeline.

The other “intelligent pig” is the Magnetic Flux Leakage (MFL) tool, which is used to detect both internal and external metal loss defects (such as corrosion) by creating a strong magnetic field. Preliminary results indicate that there are no immediate concerns with the Sumas Pipeline. The final inspection report will be complete later this summer.

The project was a joint effort between Gas System Integrity, Gas System Engineering, Construction Management, Pressure Control, Environmental & Program Services, Safety Department and InfraSource.

Outlook Spotlight: Elements of Responsible Natural Gas Production

We’re highlighting some of the sidebars featured in our 2015 Outlook here on the blog. The following is a discussion on the elements of responsible natural gas production. To access the full Outlook study please click here.

The arrival of new and abundant natural gas supplies has changed the nation’s energy picture. It also has brought new attention to gas production methods. Fracking – an abbreviation for hydraulic fracturing – is now a common term in our country’s energy debate.

In fact, hydraulic fracturing isn’t new: oil and gas developers have been using it for more than 60 years. Hydraulic fracturing uses water, sand and small amounts of chemicals to break open solid rock, releasing trapped fuels. According to the U.S. Department of Energy (DOE), more than 2 million wells have been hydraulically fractured to date and about 95 percent of new wells drilled today are fractured.

So, why are we only hearing about it now?

In the last 10 years, engineers learned how to combine hydraulic fracturing with another time-tested construction practice: horizontal drilling. Conventional drilling uses fracturing along the length of a vertical well. Now it’s possible to send fracturing equipment horizontally along a shale deposit, releasing natural gas in larger volumes than ever before.

The combination of these technologies has helped the U.S. become the world’s largest natural gas producer.

As with any industrial process, gas producers experienced a learning curve in terms of environmental protection. But as the industry and regulators have learned more about these processes, drillers are continually improving their operations. Some areas of interest are:

Water use. Increasingly, gas producers are recycling the water they use to fracture rock. Some are starting with non-potable water, and the industry is studying ways to eliminate water entirely from the fracturing process.

Groundwater. Groundwater protection is one of the highest priorities of drilling engineers. Without proper well casings, drilling fluids and natural gas can leak into the groundwater. That’s why the American Petroleum Institute has established detailed standards for well casings, and state regulators closely inspect well construction. It’s important to note that hydraulic fracturing itself has not been associated with groundwater contamination.

Disposal. The industry and regulators have established practices to prevent spills from water emerging from wells and to protect municipal water treatment facilities.

Methane. The industry has been working hard to reduce methane emissions from gas production. A recent U.S. Environmental Protection Agency (EPA) study found that total methane emissions from gas production are 38 percent lower than they were in 2005 – although gas production grew by 26 percent during that time.

Earthquakes. Increased gas production has been associated with new earthquake activity. Scientists have determined that injection wells used to dispose of water from drilling sites have caused earthquakes in some locations. Most of these earthquakes are so mild they can’t be felt on the earth’s surface.

The technology exists to help well developers avoid earthquakes. Additionally, the industry already has backed new regulations in gas-producing states to reduce earthquake potential, and a new working group through the Interstate Oil & Gas Compact Commission and the Ground Water Protection Council is now focusing on this evolving issue.

The rapid growth of gas production has spurred regulators and academics to learn more about the environmental impact of gas development. NWGA looks forward to emerging information and continued cooperation between the natural gas industry and state and federal regulators.

Sources: FracFocus, Energy In Depth, U.S. Department of Energy

Released annually, the Gas Outlook provides a detailed 10-year overview of expected natural gas demand, supply availability, infrastructure development and prices in the Northwest. The Outlook represents a consensus view of the regional natural gas market developed by industry participants that directly serve natural gas consumers in Washington, Oregon, Idaho and British Columbia. 

To access the full 2015 Outlook study along with a recording of our recent webinar with NWGA Executive Director, Dan Kirschner, please click here.

Revisiting the Recent WSU/EDF Methane Emissions Study

The American Gas Association has a great infographic highlighting some of the key takeaways from the recently published study on methane emissions and local distribution companies (LDCs). We’re excited to see the results of a study performed in part by the Northwest’s own Washington State University getting so much traction.

Click on the image below to access the AGA methane emissions landing page or read on for more information on our May webinar with Dr. Brian Lamb of WSU, who headed up the research effort.


Source: American Gas Association, click on the image to be directed to the AGA methane emissions homepage with more information.

Click below to watch a recording of our May webinar with Dr. Brian Lamb of Washington State University for more information on the study’s methodology and findings:

You can access a copy of the study on LDC methane emissions, performed by the Environmental Defense Fund and Washington State University by clicking here.

About the Presenter:
Brian Lamb is a Regents Professor and the Boeing Distinguished Professor of Environmental Engineering in the Laboratory for Atmospheric Research and the Department of Civil and Environmental Engineering. He has been at Washington State University since 1979 where he has directed a wide range of atmospheric chemistry, pollutant transport, and air quality field programs. Dr. Lamb has a special interest in biosphere-atmosphere interactions and in regional air quality modeling, particular at the intersection of global change and atmospheric chemistry. Under his direction, WSU has completed several research projects focused on the impacts of global change on regional air quality. Dr. Lamb has also been involved in national field programs to measure methane emissions from natural gas systems and landfills, and he pioneered the use of tracer ratio methods for these measurements. Dr. Lamb received his Ph.D. in 1978 from the California Institute of Technology and his B.S. in Chemistry in 1973 from Idaho State University.