Between the Poles

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.

One third of U.S. electricity generation in 2015 from non-emitting sources

According to the Energy Information Administration (EIA) since 2005 renewables have risen from 8% of total electricity generation in the U.S. to 13% in 2015.  In 2015 non-emitting sources, renewables and nuclear, provided a record 33% of overall U.S. electricity production. Roughly another third was generated by natural gas and a third by coal.

In March 2015, the United States submitted its Intended Nationally Determined Contribution (INDC) for GHG emissions reduction to the United Nations Framework Convention on Climate Change targetting emissions reduction of 26% to 28% below 2005 levels by 2025.  Electricity generation is the largest source of emissions in the U.S.  In 2015 according to the EIA carbon dioxide (CO2) emissions from electricity generation totaled 1,925 million tonnes, 21% below their 2005 level so the INDC goals appear achievable, at least for electric power.

The reduction in emissions is due to two factors, increased non-emitting energy sources with most of the increase attributable to wind and solar, and the replacement of coal with natural gas. 

There are two reasons why energy produced with natural gas is less carbon intensive than coal.  Coal plants consume more energy than a combined-cycle natural gas plant to produce the same amount of electricity.  Secondly, coal's carbon content per unit of energy is nearly twice that of natural gas. The bottom line is that to generate the same amount of electricity,  natural gas emits 40% of the carbon dioxide that would be emitted from a coal-fired unit.

Dramatic drop in levelized cost of renewable electric power generation technologies

The "levelized cost", which is the present value of the total cost of building and operating a generating plant over its financial life, aims at making the costs of different generation technologies comparable.  The US Energy Information Administration (EIA) has developed a standard way of estimating levelized costs.  The most recent estimates of the average values of levelized costs for generating technologies are for generating facilities brought online in 2020 as represented in the National Energy Modeling System (NEMS) for the Annual Energy Outlook 2015 (AEO2015) Reference case.

The levelized cost represents the per-kWh cost (in real dollars) of building and operating a generating plant over an assumed financial life and duty cycle. Key inputs to calculating levelized costs include overnight capital costs, fuel costs, fixed and variable operations and maintenance (O&M) costs, financing costs, transmission costs, and an assumed utilization rate (capacity factor) for each plant type.  Plants typically built for peaking have a much lower capacity factor or utilization rate than a baseload plant.  Renewable energy generation also typically has a a lower capacity factor because wind and sun are intermittent.  

The LCOE values shown for each utility-scale generation technology are calculated based on a 30-year cost recovery period, using a real after tax weighted average cost of capital of 6.1%.  In the AEO2015 reference case, 3 percentage points are added to the cost of capital when evaluating investments in greenhouse gas (GHG) intensive technologies like coal-fired power and coal-to-liquids (CTL) plants without carbon control and sequestration (CCS). In LCOE terms, the impact of the cost of capital adder is similar to that of an emissions fee of $15 per metric ton of carbon dioxide (CO2) when investing in a new coal plant without CCS, which is representative of the costs used by utilities and regulators in their resource planning. As a result, the LCOE values for coal-fired plants without CCS are higher than would otherwise be expected.        

U.S. average levelized cost of electricity (LCOE) for plants entering service in 2020

(2013 $/MWh)

Dispatchable	Total system LCOE
Conventional coal	95.1
Natural Gas - Combined cycle	75.2
Natural Gas - Combustion turbine	141.5
Advanced nuclear	95.2
Geothermal	47.8
Biomass	100.5

 

Nondispatchable	Total system LCOE
Wind	73.6
Offshore wind	196.9
Solar PV	125.3
Solar thermal	239.7
Hydroelectric	83.5

Comparing the levelized costs for dfferent generation technologies shows that natural gas-fired combined cycle and wind are the cheapest way to generate power in many parts of the country (without access to geothermal energy), recognizing that the levelized cost of coal includes the potential future cost of carbon emissions. 

There is considerable variation in different regions of the U.S. especially in the case of renewable energy sources.  The EIA has calculated levelized costs for 22 regions across the U.S.

Nondispatchable	Min	Ave	Max
Wind	65.6	73.6	81.6
Offshore wind	169.5	196.9	269.8
Solar PV	97.8	125.3	193.3
Solar thermal	174.4	239.7	382.5
Hydroelectric	69.3	83.5	107.2

The interesting conclusions are that wind has achieved parity with natural gas in many parts of the country and solar PV has achieved grid parity in some parts of the country(within the assumptions of levelized costs).  This represents a significant drop in the cost of non-hydro renewable energy over the past 5 years. 

Technology	2016	2018	2020
Conventional coal	100.4	100.1	95.1
Natural gas - Combined cycle	83.1	67.1	75.2
Wind	149.3	86.6	73.6
Solar PV	396.1	144.3	125.3
Hydroelectric	119.9	90.3	83.5

When I blogged about levelized costs at the beginning of 2011, the cost of solar PV per MWh was significantly more expensive than any other generation technology.  Even in 2013 solar PV was still almost 50% more expensive than conventional coal.  But now in some parts of the U.S. it is as cheap as conventional coal, though not as cheap as natural gas combined cycle. 

GITA PNW: Maintaining high quality location data about underground infrastructure pays off

At the 16th Annual GITA Pacific Northwest Conference, John Himmel, Manager GIS, at FortisBC Energy gave an overview of a remarkable geospatial solution that FortisBC will be deploying this summer.  It is a new online application service that will be available to those of the public who wish to apply for gas services. Customers will have access to a GIS map showing the location of FortisBC underground gas lines, which will enable them to know if gas is available at their location.  If it is, they will be able to see the estimated costs and arrange for a FortisBC construction crew to come and connect their home or business.  Since FortisBC receives about 50,000 calls for new service annually of which it is estimated that 2/3 can be responded to and new services scheduled by the online system, this represents a potentially large savings for FortisBC.

FortisBC's new service is remarkable for two reasons.  First of all, displaying the location of utility underground infrastructure publicly is not common.  I blogged about a water utility in North Shore City in New Zealand one of the few utilities that I am aware of that has made maps of its underground infrastructure publicly available.  

Secondly, it requires high quality data about the location of FortisBC's gas infrastructure.  Many utilities would be unable to deploy an online service application like this one, because they would not have sufficient confidence in the reliability of the information about the location of their underground infrastructure in their GIS to present is publicly.

FortisBC has been able to maintain high quality information about their underground infrastructure which has enabled them to be confident about deploying an online service application.  As further evidence of the quality of FortisBC's information about its underground infrastructure, they average about 900 pipe locate tickets every day.  These originate primarily from BC One Call and come from people who intend to excavate somewhere in FortisBC's service territory.  Because FortisBC's data about the location of its underground infrastructure is so good, 95% of these requests are handled within 12 minutes and do not require a truck roll.  Avoiding truck rolls for pipe locates represents another major source of savings arising from the quality of their GIS data.

There are many other benefits that are expected with the new online service application.  It represents a new way to interact with customers. Like many utilities, FortisBC is forging a new relationship with its customers and is going beyond just sending a bill every month.  The online system also ensures crew availability before scheduling a new hookup with the customer.  The online system also provides a automatic sales lead for FortisBC sales folks to follow up on if gas is not available at the customer location or if providing the requested service is not simple.  In addition for a significant number of new gas service installations, the customer is not prepared when the crew shows up.  The gas hookup has to be rescheduled and this wastes the crew's valuable time.  The new online system will send email reminders to the customer in advance, which will reduce the number of hookups that have to rescheduled because of customer unpreparedness.  Finally, the online system creates internal efficiencies and productivity savings by simplifying and automating processes that are currently largely manual.

GITA PNW: Geolocating dangerous underground utility intersections is big business

At the 16th Annual GITA Pacific Northwest Conference at the Boeing Future of Flight Museum in Mukilteo WA, David Steiger gave a fascinating presentation about one of the major problems arising from our poor knowledge about the location of underground infrastructure.  Cross bores are gas, power or telecom cables and pipes that bisect sewer pipes.  Horizontal directional drilling (HDD), percussion moles and plows are trenchless techniques used to install natural gas distribution and other utility lines. These boring drill heads can easily go through sewer pipes without the driller being aware of it.  Since the location of underground sewer pipes, either main line or laterals connecting the main pipes to houses, are only poorly known, cross bores are widespread.  Hydromax USA specializes in detecting and mapping cross bores.  In their experience in high risk, densely populated areas, as many as 3 cross bores per mile of natural gas distribution mainline have been found.  The average is about 0.4 cross bores per mile. 

Cross bores are dangerous.  A typical scenario is that the cross bore leads to an obstruction in a sewer pipe.  If this is a lateral, the house owner calls a plumber.  The plumber bores out the lateral with a sewer cleaning machine that has a head that can cut through tree roots, the typical source of backed up sewers, and telecom or electric power cables or gas pipes with ease.  The first documented case of a gas main being cut happened in 1976 and the resulting gas explosion killed two people and seriously injured four more.  According to Hydromax the highest claim paid for a single cross bore incident was reported at $30,000,000. 

Hydromax USA uses a robotic device that travels down sewer pipes including laterals and identifies and records the location of cross bores.  Whenever they are found, the responsible utility rolls a truck a fixes them.  Finding these problems is big business.  Hydromax estimates that in the U.S. the total market for identifying and geolocating cross bores is about $1 billion per year.

Increased recognition of the injury, death and damage caused from cross bores has resulted in federal and state regulatory action. For example, the U.S. Department of Transportation’s 2011 Pipeline and Hazardous Materials Safety Administration’s (PHMSA) requirements of Distribution Integrity Management Program (DIMP) is intended to increase the integrity of gas distribution systems.

This problem is so prevalent that the Cross Bore Safety Association has been formed.  The CBSA is a community of industry professional that have joined together to address all aspects of utility cross bores for protection against loss of life, injury and property damage.

Over $4 million awarded for fracking contaminated drinking water

In the culmination of a court case running for seven years, a jury in Pennsylvania found that Cabot Oil & Gas Corporation had been negligent and had contaminated the drinking water of two families near Dimock, Pennsylvania.  $4.24 million was awarded to the two families.  Cabot began drilling and fracking the Marcellus shale formation near Dimock in 2008.

As I have blogged about, a series of ProPublica reports identified instances where it was claimed that ground water had been contaminated in drilling areas across the United States.  The film Gasland showed examples of combustible tap water (methane in tap water) and other effects in drinking water attributed to fracking. 

The serious concerns about hydraulic fracturing’s potential impact on drinking water, human health and the environment had become serious enough that Congress appropriated funding for the EPA to undertake a major study of hydraulic fracturing and its impact on drinking water.Needless to say there is a lot of money and jobs involved.  Hence, the study was very controversial and the oil/gas companies did not cooperate.   Based on the limited evidence the EPA was able to collect, the study's draft executive summary said that it had not found evidence of "systemic, widespread effects on drinking water".  But even the study's Science Advisory Board (SAB) disagreed with the conclusion, saying the evidence did suggest a wider problem.

 A recent study by academics from Stanford in a peer-reviewed journal (Environ. Sci. Technol.,March 29, 2016, DOI: 10.1021/acs.est.5b04970) has confirmed that fracking did pollute an aquifer in Pavillion, Wyoming.  The authors state "that they have, for the first time, demonstrated impact to Underground Sources of Drinking Water (USDWs) as a result of hydraulic fracturing."

The U.S. is predicted to become the biggest oil producer in the world, ahead of Saudi.  This is largely because of hydraulic fracturing (fracking) and other well stimulation techniques, both for natural gas and oil.  There are over half a million natural gas wells in the U.S.   "Unconventional oil and gas" as fracking is often referred to has become a significant part of the U.S. economy employing millions.

But the environmental cost of fracking remains uncertain.  In 2005 Congress passed the Energy Policy Act of 2005, which was an omnibus energy bill (that among many other things changed daylight savings time in the US).  Among the provisions of the bill was one (the so-called "Halliburton loophole") that exempted hydraulic fracturing from protections under the Clean Air Act, Clean Water Act, and Safe Drinking Water Act, which means that fracking has never been regulated at the federal level (EPA).

The 2005 bill, which was passed during the GW Bush administration, prevented the EPA from doing any assessment of the environmental impact of "wild west" drilling and fracking.  However, in the last few years so many reports and two documentary films including Gasland have been circulating about water contamination from fracking that Congress authorized the EPA to do the study of the impact of fracking on drinking water quality.

Cabot Oil & Gas Corp. has asked the courts to set aside a jury’s recent verdict.

Confirmation of drinking water contamination by fracking suggests widespread problem

A new study that confirms drinking water contamination by fracking, something the EPA has been unable to do, signals the beginning of a process to assess the environmental cost of "wildwest" drilling and fracking.  This study relates to drinking water contamination.  The other area where reports are also circulating about the environmental cost of fracking is the release of methane, a potent greenhouse gas, into the atmosphere.

The U.S. is predicted to become the biggest oil producer in the world, ahead of Saudi.  This is largely because of hydraulic fracturing (fracking) and other well stimulation techniques, both for natural gas and oil.  There are over half a million natural gas wells in the U.S.  There are even wells at the Forth Worth airport to give you a feel for how ubiquitous they are in parts of the U.S. and Alberta.  "Unconventional oil and gas" as fracking is often referred to has become a significant part of the U.S. economy employing millions.

But the environmental cost of fracking remains uncertain.  In 2005 Congress passed the Energy Policy Act of 2005, which was an omnibus energy bill (that among many other things changed daylight savings time in the US).  Among the provisions of the bill was one (the so-called "Halliburton loophole") that exempted hydraulic fracturing from protections under the Clean Air Act, Clean Water Act, and Safe Drinking Water Act, which means that fracking has never been regulated at the federal level (EPA).

The 2005 bill, which was passed during the GW Bush administration, prevented the EPA from doing any assessment of the environmental impact of "wild west" drilling and fracking.  However, in the last few years so many reports (and a film) have been circulating about water contamination from fracking that Congress authorized the EPA to do a study of the impact of fracking on drinking water quality. 

Needless to say there is a lot of money and jobs involved.  Hence, the study was very controversial and the oil/gas companies did not cooperate.   Based on the limited evidence the EPA was able to collect, the study's draft executive summary said that it had not found evidence of "systemic, widespread effects on drinking water".  But even the study's Science Advisory Board (SAB) disagreed with the conclusion, saying the evidence did suggest a wider problem.

Now a study by academics from Stanford in a peer-reviewed journal (Environ. Sci. Technol.,March 29, 2016, DOI: 10.1021/acs.est.5b04970) has confirmed that fracking did pollute an aquifer in Pavillion, Wyoming.  The authors state "that they have, for the first time, demonstrated impact to Underground Sources of Drinking Water (USDWs) as a result of hydraulic fracturing."

The study involved a comprehensive analysis of all publicly available data and reports to evaluate the impact to underground drinking water sources as a result of acid stimulation (pumping acids into a well to stimulate the flow of gas or oil) and hydraulic fracturing in the Pavillion, WY, Field.  The study found that the concentrations of major ions such as chloride in samples of water from the geology surrounding wells were outside the expected levels for the aquifer, in other words, injected water and chemicals had leaked into the surrounding rock. They also found direct evidence of  leakoff of stimulation fluids into surrounding rock and inadequate casings during stimulation at several production wells.  The authors concluded that acid stimulation and fracking had impacted (polluted) the aquifer.

 

Furthermore, the authors found evidence of organic chemicals used for well stimulation in samples from two monitoring wells that had been drilled by EPA.  This was interpreted as additional evidence of impact to the aquifer and indicated that the chemicals had migrated upwards into the aquifer used for drinking water.

 

They also compiled well depths at which stimulation and fracking occurred and compared them to to the depths of drinking water wells. They found that well stimulation occurred many times at less than 500 meters from the surface and, in some cases, at or very close to depths of the deepest domestic wells.   This is evidence of shallow hydraulic fracturing, which has been shown to be of higher risk to drinking water sources than deeper hydraulic fracturing,  especially given the issues found and documented in several wells in the Pavillion field.

 

In addition they  found evidence of diesel range and other organic chemicals in domestic wells less than 600 meters from unlined pits that had been used prior to the mid-1990s to dispose of diesel-fuel based drilling mud and production fluids.

And because there is nothing especially unique about the geology and drilling around Pavillion, the study suggested that this is likely evidence of a wider problem, "given the high frequency of injection of stimulation fluids into USDWs..., it is unlikely that impact to USDWs is limited to the Pavillion Field requiring investigation elsewhere."

The problem is likely poor drilling practices and management of "produced water" because of lax or no regulation.  If the drillers neglect to put in concrete casings or if they are insufficient and leak, then the chemicals (including known carcinogens) injected into the well can get into drinking water sources.  If the water returning to the surface containing a variety of chemicals (produced water) is stored in unlined ponds as it used to be, this can also get into drinking water sources.

Latest USGS risk maps include human-induced earthquake risk

The latest USGS earthquake risk maps for the first time show the probability of earthquakes next year in the central and eastern U.S.  The new USGS hazard model estimates where, how often and how strongly earthquakes may could occur in the central and eastern United States during calendar year 2016.  Also for the first time they include human-induced in addition to natural earthquake risk. Induced earthquakes are linked to human activities the most important of which is wastewater disposal from oil and gas production operations (wastewater from fracking).

 

According to USGS the central U.S. has experienced a dramatic increase in tremors over the past six years.

 

Average number of earthquakes of
magnitude 3 or greater per year
in central U.S.
1973-2008               24
2009-2015             318
2015                    1010
2016 (to Mar 15)   226 

 

The largest recent earthquake in the region, a magnitude 5.6 tremor, occured near Prague, Oklahoma near several active injection wells.

 

By way of history the biggest earthquake in the U.S. east of the Rockies was the 1811/1812 New Madrid earthquakes of estimated magnitude 7.6 -8.0.  This occurred near the Mississippi just south of the tip of Illinois where Missouri, Arkansas, Tennessee, and Kentucky come together.  Significant risk of major seismic activity in this area continues.

New solar PV capacity exceeds natural gas additions for the first time

According to GTM Research and the Solar Energy Industries Association new solar PC capacity in the United States set a new record in 2015.  7.3 gigawatts (GW) of solar photovoltaics (PV) were installed, exceeding natural-gas capacity additions for the first time.  In 2015 solar was up 17% over 2014 and represented almost a third of new electric generating capacity additions in the U.S.

 

More than half of the new solar PV additions were utility-scale solar farms which was also a new record. Over 4 GW of utility-scale solar PV were installed which represents 6 percent year-over-year growth in this segment.  The residential solar market grew 66 percent year-over-year. The non-residential market installed more than one gigawatt of new capacity in 2015, about the same as what was installed in this segment in 2014.  The increasing rate of  installations has been driven partially by dropping prices. 

 

87% of U.S. solar PV capacity is concentrated in 10 states.
   
Total U.S. solar PV capacity now exceeds 25 GW, which is remarkably rapid growth when compared to 2010 when only 2 GW had been installed.

 

For comparison according to the American Wind Energy Association (AWEA) in 2014 about 2,500 turbines were installed, representing nearly 4.9 GW of new wind capacity.  Wind energy represented 28 % of new generating capacity installed in 2010-2014. U.S. total wind generating capacity at the end of 2015 was 65.9 GW. 

 

Capacity is one thing and actual generation another.  According to the U.S. Energy Information Administration  (EIA) in 2014 actual generation statistics show that coal, natural gas, and nuclear led by a wide margin followed by conventional hydroelectric, wind and solar.

Generation (Thousand MWh)
Coal               1,581,710
Natural gas    1,126,609

Nuclear             797,166

Hydroelectric     259,367
Wind                  181,655
All solar               27,227
Utility-scale solar 17,691
Distrib solar           9,536

Modeling underground utilities in 3D reduces construction time and costs

The location of existing underground utility infrastructure  is more often than not poorly known which creates significant risk for infrastructure and highway construction projects.  In a gas line construction project which Utility Mapping Services (UMS) submitted for a Be Inspired Award, UMS diverged from normal construction practice by first creating a  3D model of the existing underground and above ground infrastructure.  During construction there were no utility strikes and as a result there were no change orders and the construction project was completed in 7 instead of the expected 10 weeks. 

I had a chance to chat with Donald Haines, Senior Engineer, and Cameron Greer, Project Engineer at UMS.  The project involved constructing an eight inch high pressure natural gas pipeline along a major highway SR510. The customer was Puget Sound Energy which is responsible for electricity and gas in the Puget Sound area.  The Washington DOT was also involved in the project because the new pipeline runs within the SR510 right of way.

A major risk was that the project corridor includes complex utility infrastructure woven through dense commercial and residential areas with limited right-of-way and heavy traffic congestion.  Because of the complexity of the underground utility infrastructure it was decided at the beginning of the project to develop a 3D model of the existing underground infrastructure.  The model enabled the design team to adjust the pipe elevation and horizontal alignment to avoid potential utility conflicts during the design phase.  The 3d model of existing utility infrastructure avoided unnecessary utility relocations and the associated construction delays and contractor change orders. It also allowed for tighter contractor bid estimates by providing a more accurate design to the contractors. 

UMS' subsurface utility engineering (SUE) services group were familiar with new remote sensing technology such as ground penetrating radar (GPR) and electromagnetic detection (SPAR300) which allowed them to acquire 3-D location data for  underground utility infrastructure.  Application of new SUE technology created much greater value for the customer because UMS can now clearly convey to the client the issues presented by existing infrastructure and work with their design and construction teams and the utility infrastructure owners to minimize utility relocations and avoid surprises from buried unknowns.

Starting with a 2D basemap, the underground survey was conducting using several technologies, including SPAR300 and GPR, and potholing for validation.  In addition to the expected utility infrastructure, the survey detected undocumented abandoned utility lines which highlights an important advantage of the new remote sensing technologies.  The data was captured and integrated to create a 3D model using Trimble software.  The 3D model formed the basis for the design for the new gas pipeline.    The 3D model detected 170 conflicts, points of intersection of the design for the new pipeline with other utilities.  Several alternative routes were assessed and the costs and benefits of each were computed and compared in order to determine the optimal routing for the new pipeline.  3D visualization of the alternative routes helped the designers show Puget Sound Energy and the Washington DOT the advantages of alternative routes and allowed changes to be made to the design live in front of the customer.  One interesting wrinkle is that the design had to avoid conflicting with new sewer line which had not been built yet.  One of the  existing sewer lines was scheduled to be replaced by a significantly larger one in the near future.

A major advantage of the 3D model is that it reduces the risk of utility strikes during construction.  On projects where automated construction is used, exclusion zones can be created from the underground 3D model that prevent the machinery from striking utility infrastructure.

The 3D model helped in other ways.  The project required two variances from the Washington DOT which were granted in record time because the 3D model showed so clearly why and where they were required.  The 3D model helped to minimize highway disruptions to the public.  Most critically from a safety as well as cost perspective, there were no utility strikes on the project.  As a result the 3D model is credited with reducing construction time from 10 to 7 weeks.  Most importantly from a budget perspective, there were no change orders and the total cost of the project came in at 10-15% less than estimated in the absence of a 3D model.