Oil & Gas Environmental and Climate Partnerships: Tackling Methane and VOC Leaks, Limiting Wastewater Spills, Developing Best Practices Standards, and Using Best Available Technologies

Oil and Gas Environmental and Climate Partnerships: Tackling Methane and VOC Leaks, Limiting Wastewater Spills, Developing Best Practices Standards, and Using Best Available Technologies

In recent years several oil & gas environmental and climate coalitions have sprung up to address environmental, climate, and public relations issues. The Oil & Gas Climate Initiative (OGCI), a voluntary group made up of CEOs, now represents about 30% of global oil & gas production with most large majors on board. Commitments to greenhouse gas emissions reduction are featured.  API’s The Environmental Partnership is another group developing environmental standards as is the Appalachian Basin based Center for Responsible Shale Development. ONE Future (short for Our Nation’s Energy Future) is a coalition of 16 companies including some midstream and utility companies. They have coordinated with the EPA and the DOE’s NETL to curb methane and total greenhouse gas emissions.

The Center for Responsible Shale Development (CRSD) involves oil and gas producers as well as environmental organizations. CRSD requires companies to meet certification requirements and to recertify periodically which is verified by a third party. CRSD is centered in and currently limited to the Appalachian Basin.

According to their website CRSD “has created 15 forward thinking, high performance standards focused on Air, Climate, Water, and Waste — standards that often exceed state and federal requirements.” These standards include effluent management and monitoring, water recycling requirements, surface and groundwater protection plan, tracking water usage, double-lined containment in pits and tanks and clean tank requirements, pre-drill baseline water testing and local aquifer analysis, some post-well groundwater monitoring, chemical disclosure, minimizing or discontinuing use of harmful chemicals where possible, developing leak-proof drill pads, safety and emergency response plans, limited flaring or venting of gas, documentation and reduction of engine emissions and compressor emissions of VOCs, NOx, particulates, CO, and other pollutants, utilization of controls and valves that limit ‘bleed-off’ and reduce emissions of methane and VOCs from tanks and compressors, utilizing the most sustainable completion practices, and emissions requirements for trucks hauling flowback water. They have a detailed comparison of CRSD standards vs. federal standards and the standards of three main Appalachian shale states (Ohio, Pennsylvania, and West Virginia) for each criteria.

API’s The Environmental Partnership shows 52 member oil & gas companies, including several majors and many large independent companies. One of their goals is to improve the industry’s environmental performance through standardization, collaboration, and learning. They have standards similar to the CRSD standards for low-bleed pneumatic controllers, minimizing emissions during liquids unloading, and leak detection and repair. They also present workshops, field trips, and just had their first annual conference. There are also other consortiums hosting conferences about environmental aspects of energy production and consumption.

A recent report by DOE’s National Energy Technology Lab (NETL) shows that members of the ONE Future coalition have very significantly reduced methane emissions far below standards they initially set for 2025. This shows that emissions reductions are happening quite successfully and feasibly. The NETL utilizes ‘life cycle analysis of energy technology and pathways.’ The report analyzed life cycle emissions from all phases of gas production including production, gathering & boosting, processing, transmission/storage/blowdowns, and distribution. In every category except distribution the ONE Future companies had achieved significantly less emissions than the rest of companies in the U.S. The reason is the addition of midstream and downstream utility companies with lots of legacy assets that include outdated leaky cast iron pipe which continues to be replaced but that replacement is slow-moving due to the nature of distribution systems being in highly populated areas. The ONE Future companies represent from 5-12% of U.S. natural gas production according to the report. The report also offers insights for prioritizing abatement of emissions sources according to both cost and product recovery. Some sources are continuous (ie. leaks in pipelines) and some are episodic (ie. liquids unloading and flaring). Life cycle analysis, inventory assessment, and cost analysis all can suggest which leak repairs to prioritize. 

Despite Trump administration efforts to rollback any federal rules regarding oil & gas industry methane emissions there is still a strong and successful push to decrease emissions. At some point this will likely extend to legacy well owners which will be more of an economic burden on these producers of marginal wells. As leak detection and repair technologies come down in price it will become more economically feasible. It could even be wise to offer some financial incentives or tax breaks to those legacy producer companies who can show methane emissions reductions. I think this is important since if methane emissions are tackled and reduced significantly, as has been done by the ONE Future companies then that would make natural gas even more sustainable as a bridge fuel toward the gradual and inevitable transition to renewables, storage, electrification, and clean energy.  

There are other partnerships and assessments involving academia, environmental orgs like Environmental Defense Fund, and industry, that have assessed leak detection needs and cost analysis, water management, spills and containment and other environmental issues. The U.S. EPA, the DOE, and other federal and state agencies are partnered in these assessments and studies.  

References:

Working together to tackle climate risks – by Darren Woods, in Energy Factor by ExxonMobil, Sept. 20, 2018

Exxon and Chevron join industry climate change group – by Ed Crooks, in Financial Times, Sept. 20, 2018

Natural Gas Companies Plug Leaks, Easily Surpass 2025 Goal – by Darren Barbee, in E & P Magazine, Nov. 25, 2018

www.responsibleshaledevelepment.org (CRSD website)

www.theenvironmentalpartnership.org (website of API’s The Environmental Partnership)

Industry Partnerships and Their Role in Reducing Natural Gas Supply Chain Greenhouse Gas Emissions – by National Energy Technology Laboratory, May 1, 2018

Unlikelihood 0f Appalachian Thermal Coal Revival Amidst So Many Combined Cycle Natural Gas Plants Under Construction (and the reported planned withdrawal of proposed coal and nuclear bailouts)

Unlikelihood of Appalachian Thermal Coal Revival Amidst So Many Combined Cycle Natural Gas Plants Under Construction (and the reported planned withdrawal of proposed coal and nuclear bailouts)

The Trump administration plan to revive Appalachian coal by monetizing it through government subsidy was said to be justifiable by concerns about fuel security (90 days of fuel on-site).  Different versions have been floated about reviving coal: WV governor and billionaire coal company owner Jim Justice’s suggestion for an eastern coal subsidy to keep mines open and stave off bankruptcies, Energy Secretary Rick Perry’s Grid Reliability study intention of supporting energy security path to prop coal backfired a bit as the study suggested grid reliability was adequate, and Perry’s Murray Energy-approved plan to subsidize coal plants with 90 days of fuel on-site.

Meanwhile the Appalachian and nearby Midwest and Atlantic Coast regions continue a large buildout of efficient combined-cycle natural gas plants. According to Kallanish Energy, there are 29 gas plants in various stages of planning and construction in the Appalachian region. These plants are fairly close to the gas source and now with good pipeline access to different areas. Being close to fuel source makes the plants more economic with the Appalachian basis differential keeping Appalachian natural gas locally cheaper.  

The planned coal and nuclear bailout was touted to be justified by national security concerns and evoke wartime emergency powers rules from 1950. However, recent leaks have suggested that cost and legal difficulties will influence the administration to drop the plan. There are some, though likely few or none in the current administration, who might favor some form of nuclear energy bailout to keep low carbon energy sources afloat but who reject coal bailouts. Basically, utilities concluded that there is no credible threat to fuel security due to scheduled retirements of coal and nuclear plants. Even the American Petroleum Institute opposes the bailout. Some nuclear energy companies even oppose it. While fuel on-site can potentially help during polar vortices the reality is that it often doesn’t. Some equipment at coal plants apparently froze up during the last polar vortex. Frozen on-site coal is also sometimes a problem that can negatively affect equipment. Hurricane Harvey flooded some on-site coal supplies at power plants and winds at tropical storm strength have shut down coal plants while not affecting wind turbine operation in the same region. Again, with Hurricane Florence in the Carolinas, some coal and gas plants shut down while solar power remained operational. Nuclear plants are subject to unscheduled outages for maintenance which also can be weather-related. I think the bottom line here is that coal and nuclear are not as resilient and secure as some think, especially compared to natural gas which is generally not affected by weather. It can, however, be affected by pipeline flow interruptions and price spikes in polar vortices – with the price spikes being the main reason coal is used more in these cold weather events.

However, some industry execs praised the effort to prop up coal and nuclear in the name of grid reliability and resiliency. Exelon Energy CEO Christopher Crane said in June at the Edison Electric Institute’s annual convention that “getting the market design right and looking at the resiliency is really a requirement that we need federal intervention on” referring to the increasing amounts of natural gas and renewables on the grid. He noted that utilities don’t currently have resource planning at the national level. However, it can be argued that they do on a regional level as some regional utility operators like PJM Interconnect, which represents 30% of U.S. power generation, have done broad reliability and resiliency analyses. They actually predicted grid reliability up to 86% natural gas. Currently gas an coal are fairly even in that region with about 30% each. So, I am guessing the need to incorporate coal into reliability and resiliency planning differs a bit by region but overall it does not seem to be a big problem. In Western states like California where solar is huge or in the Midwest where wind is a big part of generation the issue in the future is mainly backing up intermittence with more reliable baseload generation, which csan be provided by natural gas, coal, hydro where applicable, and/or nuclear.

There was also an announcement from the DOE back in March about funding for small modular coal plants, possibly as peaker plants, but it is hard to see how these could really compete with natural gas peakers. The DOE spokesman touted these types of plants as a way to bring coal back so it sounds like the politics of reviving coal is involved. The question is: why do it with coal when you can do it with cleaner, less carbon intensive, more efficient, and cheaper natural gas?

The price of natural gas relative to the price of coal is not expected to change much in the coming years so coal won’t revive under market conditions. Metallurgical coal for export is currently the continued plan for met coal producers while thermal coal producers will continue to contract. Even if steel production increases in the U.S. due to tariffs that will only benefit met coal producers. The EIA predicts U.S. consumption of coal will drop by about 6% in 2019 relative to 2018. The drop in 2018 is expected to be about 4% so this is a slightly bigger drop than in previous years. Exports are forecast to drop about 8% in 2019 relative to 2018 – they had risen by quite a bit, nearly 50%, from 2016 to 2018. Nearly all of the drop is in the electric power sector. Electric Power Sector Coal Inventories are predicted to rise a percent or so in 2019 relative to 2018 but have dropped considerably from 2016-2018. They are expected to remain pretty steady over the next few years.

Bottom line is that paying coal companies to store more coal than they currently do at coal power plants probably won’t really add to our energy security and it seems likely none of the extra stored coal would be used.

References:

Appalachia has 29 gas-fired power plants in various development stages – by Kallanish Energy, Oct. 11, 2018

Trump Administration to drop Its Emergency Coal, Nuclear Bailout Plan – by Jeff St. John, in Green Tech Media, Oct. 16, 2018

Everybody hates Trump’s coal and nuclear bailout plan – by Mark Hand, in Think Progress, July 7, 2018

Breaking Down the Opposition to DOE’s Emergency Coal and Nuclear Bailout Plan – by Jeff St. John, in Green Tech Media, June 1, 2018

Exelon CEO: ‘We Need Federal Intervention’ on Grid Resilience – by Julia Pyper, in Green Tech Media, June 6, 2018

Trump’s Energy Department pursuing small coal power plants – by Amy Harder, in Axios, March 7, 2018

Energy Information Administration (EIA) – Short-Term Energy Outlook – Coal, Oct. 10, 2018

Colorado's Initiative 112: Overkill Setback Regs That Could Devastate the State's Oil & Gas Industry If It Passes

Colorado’s Initiative 112: Overkill Setback Regs That Could Devastate the State's Oil & Gas Industry If It Passes

Common state setback requirements for oil and gas facilities and equipment from dwellings are about 500ft as is the current requirement in Colorado. On the state ballot this year for voters to decide is a setback requirement of 2500 ft – 5 times the avg. This would put huge swaths, 50-60% of the state’s surface land mass, totally off limits. According to the Colorado Oil & Gas Conservation Commission it would put about 85% of the surface of non-federal lands off-limits. The proposed setback rules do not affect public lands, which cover about 35% of the state. Of course, resources appear where they appear regardless of land designations. Cities and towns have existing zoning laws that precludes oil and gas facilities. Landowner groups formed in some areas to influence the siting process as applicable. However, oil & gas companies have a need to consider well spacing and geology to optimize resource recovery.

Revenue and employment from the state’s considerable oil & gas industry would fall drastically. I can understand increasing the setback distances a little bit, even doubling them to 1000 ft but the 2500 ft rule is clearly overkill designed to destroy the industry. The Denver-Julesburg (DJ) Basin is home to lots of closely spaced wells and to much new housing and development which can justify some increase of setbacks. However, the 2500 ft proposal is far greater than typical even in other states where oil & gas development overlaps with populated and developing areas. The initiative would potentially put 78% of Weld County, the heart of the DJ Basin, off-limits and even more than that for the most economic areas. That would wipe out drilling by most E&Ps in the area.

Reasons for increased setbacks include air quality, possible water well impacts, noise, truck traffic, lights, even vibrations in some cases. The Colorado Department of Health recently concluded a study of the air quality impacts from oil & gas facilities and wells and found that they do not constitute a hazard. Water well impacts are not likely either. Noise, lights, and truck traffic can be mitigated.  

Personally, I do not think this is something that should be on a statewide ballot. For one, I am guessing the percentage of the state’s population that lives less than 1000 ft, even less than 2500 ft, from oil and gas production facilities is small compared to the state population. Most people live in towns and cities and so the issue by and large affects rural people exclusively. Yet the much greater number of unaffected people in cities get an equal vote. That does not seem fair. Most political, social, and environmental issues involve where to put the line between acceptable and unacceptable. New administrations are voted in and out and those lines often change. However, they usually do not change by leaps and bounds. If this initiative passes that will change.

The issue also affects landowners who want to drill on their property, potentially taking away some of their property rights to lease their minerals and benefit financially from wells drilled on their property.

If the initiative passes it will affect the 6-8% of Coloradans employed in oil and gas. It would affect taxes and fees the industry provides to local governments. One think tank predicted it could cost 150,000 jobs and cut state GDP by $218 billion over time. Former governor Bill Ritter, a Democrat, noted that Colorado has “the strongest set of regulations in any state in the country where oil and gas extraction is concerned and where hydraulic fracturing is concerned.” Current governor John Hickenlooper, also a Democrat, has long supported fracking as well as Colorado’s strong regulatory environment. He is also a geologist who knows about oil and gas. As Jude Clemente points out in the Forbes article referenced below stifling oil and gas development will mean less natural gas available to back up renewables and to mitigate climate change through replacing coal.

BTU Analytics, an energy market analysis firm based in Denver thinks there is an even chance the initiative will pass since the state has seen population increases, a younger demographic, and an overall move to the left politically. They also note that the proposal might well sound reasonable to a layman who doesn’t know much about oil and gas.

An article in the academic journal, Social Forces, interviewed 100 landowners about relations with the oil & gas industry focusing on things like lease terms and addressing of complaints. They concluded that the industry has the upper hand and increases what they called “procedural injustice.” They approached the subject from an environmental justice standpoint, apparently. However, I do know that industry does very often attempt to accommodate landowner concerns. Industry must consider optimization of their resources, which basically translates to efficiency of development, which maximizes profit and decreases environmental impact per energy unit produced. Geology, well-spacing, surface topography, and lease boundaries must be considered. As stated above many areas have landowner groups who develop their own lease terms and negotiate as a group so that terms are equal and no one gets disadvantaged by industry negotiators, typically landmen. I think the industry should have the upper hand since it is they who need to decide where to drill. Otherwise they might not drill at all and everybody loses. They can’t and won’t drill in spots where they are too far less than optimized.  

References:

Study Shows Oil & Gas Industry Wields ‘Meta Power’ But Colorado Residents are Fighting Back – by Mark Hand, in ThinkProgress, Oct. 5, 2018

Colorado’s Initiative 97 Unwisely Blocks Oil and Natural Gas Development – by Jude Clemente, in Forbes, Sept. 30, 2018

Making Heads and Tails of Proposition 112’s Chances of Passing – A Coin Flip? – by Tony Scott, BTU Analytics, Sept. 27, 2018

The Right to Resist or a Case of Injustice? Meta-Power in the Oil & Gas Fields (Abstract) – by Stephanie A. Malin, Tara Opsal, Tara O’Connor Shelley, and Peter Mandel Hall, in Social Forces, Sept. 21, 2018

DJ Basin: Is the Future Setback? – by Matt Hagerty, in BTU Analytics, July 17, 2018

Crude-By-Rail Expected to Triple as New Oil Pipelines are Beset with Protests and Regulatory Hurdles: Why Pipeline Transport of Oil is Safer, Cleaner, Cheaper, and More Sensible

Crude-By-Rail Expected to Triple as New Oil Pipelines are Beset with Protests and Regulatory Hurdles: Why Pipeline Transport of Oil is Safer, Cleaner, Cheaper, and More Sensible

It is considerably more expensive to ship crude oil by rail compared to pipelines. Pipelines are also a much safer way to transport crude than by rail. However, due to the time constraints in building oil pipelines due to regulatory hurdles and considerable public opposition to them, both in the U.S. and in Canada, it is inevitable that more and more North American crude will by shipped by rail. Shipping by rail also requires the burning of massive quantities of diesel fuel compared to pipelines which only utilize pumping every few hundred miles. This makes the carbon footprint much higher for crude-by-rail vs. pipelines. The possibility for spills and accidents is higher for the trains, and although the spills are smaller than for pipelines, the accidents can be devastating.

It has recently been reported that shipping crude by rail is expected to double in 2018 compared to 2017 and triple in the coming years and much of that crude will be heavy oil from Canada’s Alberta tar sands fields and Western basins and be shipped to the U.S. Gulf Coast. One analyst predicts that Canadian crude exports via rail will increase from 200,000 barrels per day to 600,000 barrels per day by 2021. Crude is still in high demand in North America and is expected to remain that way for a while so the assertions by some economists that Canadian heavy crude, especially tar sands crude, is not in demand due to its quality, are simply incorrect. However, I do know that transporting heavy tar sands oil via pipeline requires the addition of diluting agents, basically lighter hydrocarbons such as natural gasoline and condensates. This helps to decrease the viscosity of the heavy crude so that it can flow more readily in pipelines. Some have argued that the heavy crude is more likely to spill from pipelines but this is not born out by statistics. It may be harder to clean up after a spill though, but I am not sure of that either. Despite the higher cost to ship via rail the heavy Canadian crude can more than make up that cost by shipping to the U.S. Gulf Coast where it is in high demand. The Canadian issue is the need to get crude to the higher price markets in the U.S. even if the cost to ship by rail is $15-19 per barrel compared to $7 per barrel if transported by pipeline. The gridlock in the construction of the Keystone XL pipeline has been lifted somewhat by Trump’s approval of the project but for now the only solution is to ship by train.

While pipeline spills are often much higher volume spills than those by train or truck, there are far more spills via train and truck. There is also the concerning issue of the flammable nature of the crude. Bakken crude from North Dakota in particular has been quite explosive in accidents. Requirements for better built tanker cars and vapor pressure limits to decrease volatility before shipping may help to prevent future explosions. Train speed limits may also help.

This is another situation where anti-pipeline activist environmentalists are actually causing more potential environmental damage, more pollution, more carbon emissions, as well as hindering profits by blocking and delaying the safest way to transport a product in high demand. While they also seek to limit crude-by-rail, referring to them as “bomb trains,” at the same time they are enabling more trains by opposing pipelines.

References:

Cenovus to move 100,000 bpd of oil by rail to Gulf Coast – by Nelson Bennett, in BIV.com, Sept. 27, 2018

The Pros and Cons of CAFE Standards: Do CAFE Standards Compromise Vehicle Safety As Conservative Think Tanks Claim? How Does the Rebound Effect Fit In? Fed Rule vs. State Rules

The Pros and Cons of CAFÉ Standards: Do CAFÉ Standards Compromise Vehicle Safety as Conservative Think Tanks Claim? How Does the Rebound Effect Fit In? Fed Rule vs. State Rules

In 2009 Obama announced a new upgrade to CAFÉ standards to increase vehicle mileage. He stated that the goal was a 5% annual average increase in miles per gallon (MPG) without compromising safety. The Competitive Enterprise Institute, headed by Trump transition team member Myron Ebell, has argued for years now that lowering the standards by making vehicles lighter, likely the most important component to MPG increases, has compromised safety. Is this actually true? Other conservative think tanks such as the Heartland Institute have made the same arguments as have some safety experts.

Every vehicle is given a safety rating based on actual crash tests. Vehicle weight is very often a factor in safety and fatalities but not the only factor. Engineering design is a factor as well as are vehicle size, types of materials used, smaller engines, more complete combustion and recombustion, and even country of origin. Aside from car company tests there are agencies like National Highway Traffic Safety Administration (NHTSA) and the Insurance Institute for Highway Safety (IIHS) which give safety ratings and do meta-analysis to compare vehicles. Studies by the National Research Council in 1993 and the Harvard Center for Risk Analysis both concluded that CAFÉ standards did indeed contribute to more highway fatalities, thousands per year in the first study and hundreds per year per mpg in the 2^nd study. The IIHS found in a 2007 analysis that some SUVs with low safety ratings have higher fatality rates than some small cars with high safety ratings. In crashes involving cars and SUVs the weight of the SUV directly correlates to higher fatalities among car occupants – the heavier the SUV the more deaths. There was no mention of whether the weight variance of the small cars affected fatality rates. Another study showed that 75% of traffic fatalities involved a truck. Those last two data sets suggest that lowering the weight of trucks and SUVs might have more of an impact on reducing fatalities than making small cars heavier or keeping them the same weight. Thus, the argument is whether lighter cars are the main problem or the lesser problem as that data suggest, the bigger problem perhaps being the bigger differences in weight. That data also suggest that the earlier studies may have overestimated the effect of the CAFÉ standards on safety since lighter cars with better gas mileage are increasingly sought by consumers anyway for the cost savings and environmental benefits. A 2003 study by the Transportation Research Board suggested that engineering design was a more important factor than vehicle weight in determining safety. The bottom line is that while vehicle weight does affect safety, it may not be the main factor and since consumers want and expect vehicles with higher fuel economy, the relative amount of lighter vehicles on the roads are likely to continue to increase at similar rates regardless of whether CAFÉ standards are continued or frozen as the Trump proposal calls for beginning in 2021.

Other arguments against CAFÉ standards are touted by vehicle manufacturers who say that the changes add significant costs to production and that consumers are less willing to pay higher prices for smaller cars costlier to produce. If they pay more they want bigger vehicles. That may be less and less true as time goes on, though bigger vehicles for bigger families and trucks for transporting stuff will continue to be sought. However, it is interesting that the big car makers spend much more on advertising for their bigger and more gas guzzling models, which suggests that they have higher profit margins on those vehicles.

Fuel economy standards were first enacted in the U.S. in 1975 in response to oil embargos and began to be implemented in 1978 increasing about 1-2mpg per year. With some very minor ups and downs fuel economy standards were essentially frozen from 1985 until 2011 when they went from 27.5 to 30.2 for passenger cars. That is 26 years of R&D into increasing fuel economy while it was held steady. Current research involves automated vehicle safety technologies, similar to those used in automated driverless vehicles. Such technologies should be able to help reduce injuries and fatalities.

It has recently been announced (first in 2016) that the transportation sector has overtaken the power generation sector in greenhouse gas emissions. CAFÉ standards as a form of efficiency have always been touted as a very good and very feasible way of reducing pollution and greenhouse gas emissions. 60% of transportation sector emissions are from cars and light trucks.  

Another argument against relaxing fuel efficiency standards is that it would mean we would import more oil from OPEC which keeps us dependent on those players and adds to trade deficits. Thus, increasing fuel economy can increase U.S. energy independence. Yet another argument is that such standards would decrease particulate pollution and other pollution like VOCs and oxides that contribute to ground-level ozone and smog. That is probably the main reason why the state of California has long sought higher CAFÉ standards than the U.S. as a whole. However, the new Trump administration proposal seeks to compel California to accept the national standards that would effectively increase such emissions from where they are now. Apparently, the Clean Air Act gives states the ability to set their own fuel economy standards subject to EPA approval. It appears that EPA head Andrew Wheeler and company are not willing to continue that approval, which is an odd departure from an EPA that has sought to give states more freedom enact regulations without interference from the federal government. The Scientific American article referenced below points out that despite California’s more stringent standards they have the poorest air quality in the nation. This has much to do with the weather inversions that cause the urban smog to remain in the close to the ground.

Competitive Enterprise Institute’s Myron Ebell argues that not freezing CAFÉ standards affects consumer choice by making the cost of new cars higher. Of course, any added cost will be more than offset and recouped quickly by savings in fuel costs. He rightly points out that CAFÉ standards were originally designed to increase U.S. oil independence and that the shale revolution has really helped with that goal. He also notes that Obama invoked a 2007 Supreme Court decision to repurpose CAFÉ standards as a way to decrease greenhouse gases. Ebell makes another interesting argument: that higher sticker prices for cars (presumably due to the need to increase MPG) is causing more people to keep their older cars on the road, cars that are less safe and less efficient. That is a difficult claim to evaluate. I tend to doubt that adding $1000-$2000 to a $20,000 to $50,000 vehicle is having a large effect on buyers. However, those costs may increase to $3000 more per vehicle if the ratcheting up to 2025 is continued as planned. That could have a bigger effect on consumers. Oddly, the title of Ebell’s op-ed says the new Trump CAFÉ freeze would lower gas prices but there is no mention of gas prices in the article at all. It can be argued that continually ratcheting up the fule economy will continue to increase vehicle costs and that is perhaps a good argument for freezing or reducing future increases as the new Trump EPA plan does. He also notes that rising vehicle costs also price lower income people out of the new car buyer market – even though they would save on fuel costs the higher purchase costs are prohibitive.

Apparently, there are around 15 states with CAFÉ standards similar to those in California. Many of those states are among the 17 states that have recently sued the EPA to keep their own standards. In June, Colorado became the 14^th state to enact such standards.

Obama’s EPA finalized an evaluation in Jan. 2017 that found that implementing the standards through 2025 was feasible and the benefits would outweigh costs. The Trump EPA under Pruitt began to rewrite the standards and current head Andrew Wheeler and Secretary of Transportation Elaine Chao recently announced the proposed new rules.

Rebound Effect – Real but Limited

Of course, with lower fuel costs people are likely to drive more. This is known as the rebound effect – when something becomes more efficient it usually becomes cheaper so that in cases where cost would curb use there would be more use. In driving, the degree of the effect probably has to do with how much driving one does regardless of cost, necessary driving and leisure driving. Only leisure driving would increase and only to an extent. In terms of driving the rebound effect has been dubbed the “Prius effect.” The Trump administration argument for freezing CAFÉ standards noted that the lower fuel costs would lead to more driving and thus more accidents. That is likely true to a certain small extent. Skeptics of the strength of the rebound effect note that most people are not looking to drive more and the effect is negligible, say Ted Nordhaus and Alex Trembath of the Breakthrough Institute, a moderate environmental think tank. They also argue that increased engine efficiency has been directed toward selling bigger vehicles that are more efficient rather than smaller ones, while the increasing CAFÉ standards favor the smaller vehicles. They note that one could make the argument that decreasing the weight of vehicles overall or of heavier vehicles can reduce injuries and fatalities just as much or more than increasing the weight of lighter vehicles – as the evidence indicated above about varying vehicle weights on accident fatalities suggests. Another thing they note is that vehicle safety per miles driven has been increasing steadily through time. This is due to better technology, more comprehensive safety regulations, and stricter drunk driving enforcement. Alex Trembath argues that while CAFÉ standards were effectively frozen (1985-2011) vehicles got bigger and more powerful. Thus the rebound effect of frozen CAFÉ standards was toward driving bigger and more powerful vehicles, since higher efficiency technologies can make those vehicles meet the standards if they don’t rise.

Federal CAFÉ Standards vs. State Standards

About 14 states now have standards close to those of California, which are even stricter than the national standards, This represents over 40% of new cars and trucks being manufactured. Myron Ebell at CEI touts the relaxing of the standards as a victory against government overreach, both of the feds and in this case against the ability of a state like California to influence the policies of other states. He says California has been “pursuing an anti-car agenda for decades.” He says that without noting the direct impact of fuel-burning vehicles on California urban smog. He advocates, “kicking California bullies out of the fuel economy playground” to expand consumer choice. Of course, this does not address the other 13 or 14 states with similar standards. He argues that the original CAFÉ standards did not foresee states having their own standards and this is a good argument although there has been considerable debate in legal circles since the Clean Air Act does gives states some rights to regulate their own air quality and in states like California it is definitely an air quality issue. Of course, in most instances conservative views of environmental regulation refer to the states to set standards, now presumably especially if those standards are less stringent than federal standards. This is not the case here. He does complain, perhaps justifiably, that California has had too much influence on the federal standards, citing specific cases. It is thus debatable whether California has had undue influence through its “fuel economy zealotry.” California also promotes other low emissions technologies such as natural gas vehicles (NGVs), electric vehicles (EVs), high quality and functioning catalytic converters, and other technologies that increase fuel economy and reduce emissions. While Ebell and Co. do make some valid arguments they also seem to want to punish left-leaning states like California (without mentioning smog at all) as part of what Ebell calls the “climate -industrial complex.” This issue is one of several involving the Trump administration being at odds with California and several other states: fuel economy standards, sanctuary cities, and net neutrality, are three I can think of although they are very separate issues.

The Big Picture: Recap of Pros and Cons of Current CAFÉ Standards Trajectory

Pros:

1)      Saves consumers substantial $ on fuel

2)      Reduces particulate and smog-producing pollutants – vital in cities and certain regions

3)      Reduces greenhouse gas emissions from its largest domestic source

4)      Increases U.S. energy independence

5)      Can help states meet their own emissions standards – a real benefit in high pollution areas

Cons:

1)      Likely reduces safety – by how much is questionable

2)      Increases costs for automakers – higher costs for consumers more than recouped by fuel savings

3)      Could make some repairs more expensive for consumers – through higher materials and replacement costs.

4)      Rebound Effect – people will tend to drive more if fuel cost is cheaper due to better mileage, although only a portion of the saved fuel will be burned due to rebound

5)      Higher cost of new cars causing people to keep less safe, less efficient cars longer (questionable how big this effect really is) and price lower income people out of new car market

My own opinion is that there is some basis for freezing or reducing the future increases of the Obama EPA rule but that there is little to no basis for restricting states rights to set their own standards, particularly high smog states like California.

References:

Americans' love affair with cars threatens climate goals – by Maxine Joselow, E&E News reporter Climatewire: Wednesday, September 5, 2018

Using Trump’s Bad-Faith CAFÉ Standards Proposal to Better Understand Efficiency Rebound – by Ted Nordhaus and Alex Trembath, in Green Tech Media, Sept. 11, 2018

How to Reap the Benefits of Fuel Efficiency Standards – by Alex Trembath, in BreakThrough Newsletter, Sept. 19. 2018

Relaxing Vehicle Efficiency Standards Is a Truly Dangerous Idea – by Rob Jackson, in Scientific American, July 1, 2018

Wikipedia Entry – Corporate average fuel economy

Colorado Becomes 14^th State to Adopt Stronger Vehicle Emissions Standards – by Mark Hand, in Think Progress, June 19, 2018

More Realistic Fuel Economy Rule Would Cut Traffic Fatalities and Lower Gas Prices – by Myron Ebell, op-ed in Arizona Daily Star, Aug. 15, 2018

CEI: Proposed Changes to CAFÉ Standards Are Good News for Consumers – by Myron Ebell, Sam Kazman, and Marlo Lewis, in Competitive Enterprise Institute, Aug. 2, 2018

Will Trump Auto Rule End California’s Regulation of Fuel Economy – by Marlo Lewis Jr., in Competitive Enterprise Institute, Aug. 1, 2018

Fracking Improves U.S. Energy Independence, Reduces GHG Emissions and Pollution, Provides Good Jobs, and Saves Us Money: It's Hard to Deny the Benefits

Fracking Improves U.S. Energy Independence,  Reduces GHG Emissions and Pollution,  Provides Good Jobs, and Saves Us Money: It’s Hard to Deny the Facts

U.S. oil production has more than doubled since 2011 thanks to the ‘shale revolution’ dependent on high-volume hydraulic fracturing and horizontal drilling. It’s been 20 years now since George Mitchell and company first proved up the modern process in its crude form by accelerating production of the Barnett Shale in the Fort Worth Basin. 

Below is a chart of increasing U.S. oil production that shows we have overtaken both Russia and Saudi Arabia to become the world's largest oil producer:

The U.S. has also become the world's largest natural gas producer. The graph below from EIA data shows the increase in U.S. natural gas production over the last decade:

Benefits vs. Risks

Not only has fracking solved for the foreseeable future our past problem of a shortage of natural gas, allowing us not to become dependent on nations like Russia and Qatar, but also has increased our oil independence so we have become far less reliant on countries like Saudi Arabia, Venezuela, Iraq, and Nigeria for oil. It has allowed us to move away from coal in electricity generation, providing cleaner air and less greenhouse gas emissions. In fact, U’S carbon emissions are nearly 14% lower than they were in 2005 and fracking, or rather gas availability for replacing coal in power plants, is the main reason why. The U.S. economy grew by 20% during that time period so environmentalists who previously attempted to credit the 2008 economic downturn and renewable energy as the reasons for the decline have been proven to be incorrect.  It has made electricity much cheaper than it otherwise would have been. In 2017 U.S. carbon emissions reductions continued by dropping 0.9% while European emissions rose by 1.6%.

The oil & gas industry provides good-paying jobs in the regions it is produced. It has also helped to make gasoline and oil distillate products cheaper. With Obama’s lifting of oil export restrictions oil producers have more strategic options for selling oil. Liquified natural gas (LNG) and natural gas liquids (NGLs) are being increasingly exported from the U.S. around the world as well. Natural gas power generation has gotten more efficient with modern combined-cycle plants and offers superior back-up generation for intermittent wind and solar, especially with the addition of peaker plants with digitization and battery power for quick start-up. New processes like the Allam Cycle indicate that gas plants are the most economic to equip with carbon capture technologies. Natural gas is also very functional to incorporate into microgrids for reliable back-up power. Air quality has improved drastically in areas where gas has replaced coal, fuel oil, and wood for heat and power generation. There is also much potential to reduce pollution and carbon emissions from trains, ships, long-haul trucks, fleet vehicles, and heavy equipment from switching from diesel to natural gas. Low natural gas prices predicted into the future mean that the cost for such conversions will be recovered with lower operating costs. Fracking and related activities like building pipelines have also been very good to state and local tax revenue. The bigger companies also donate large sums to local development, schools, facilities, disaster relief, environmental causes, and wildlife restoration. Landowners, rich or poor, have reaped the monetary rewards of leasing and drilling. Cabot Oil & Gas, who operates in one county in Pennsylvania recently recognized the milestone of paying out $1 billion in royalties to mineral owners. Those are the benefits. The risks are mainly accidents in the form of spills, leaks, and explosions. These happen but data show that they have not increased since fracking-based U.S. oil and natural gas production have drastically increased. The risk of methane leakage, which does have a high global warming potential in the short-term, is manageable and many companies have committed to reduce such leakage to levels at or below current government standards. Water contamination is an ongoing risk, particularly from spills but that risk is manageable and has yet to cause any widespread issues. The risk of induced seismicity (small earthquakes) from wastewater injection (and hydraulic fracturing in certain areas) is now much better understood and can and will be mitigated as current strategies to reduce such events are working.

An excellent piece appeared recently in the Washington Examiner as an op-ed by Seth Whitehead, who writes on behalf of Independent Petroleum Association of America (IPAA)-funded industry advocacy group Energy In Depth. He laid out the benefits and risks of fracking and correctly concluded that the benefits by far outweigh the risks. The economic benefits far outweigh the economic risks. The environmental benefits far outweigh the environmental risks. The benefits to consumers, to energy security, and to employment are very significant. That is not to say there are no risks. There are. However, the risks have been far overblown by anti-fracking and ani-fossil fuel interests. As mentioned in the article some of the claims are unfounded and some of the headlines are ridiculous, for instance, claims about fracking affecting health of people who live near well sites. In reality, overall air quality has improved dramatically due to gas replacing coal in power plants. Some of these studies were funded by anti-fracking groups. The Colorado Dept. of Public Health and the Environment in a 2017 study of air quality near oil and gas well sites concluded after collection and analysis of 10,000 air samples that “The risk of harmful health effects is low for residents living [near] oil and gas operations.” The Obama-era EPA concluded that there is no widespread effect on drinking water due to oil and gas operations even in areas where there is more risk due to the proximity of gas-bearing zones to freshwater-bearing zones – although there was some backlash by EPA’s Science Advisory Board (which at the time did not include any members associated with industry). Yes, there were some local water sources affected by methane migration and by spills, but the problem is not widespread nor is the damage permanent.  

Local Economic Benefits for the Appalachian Region

The Appalachian region that includes the Marcellus Shale, the Upper Devonian Burkett Shale, and the Utica Shale is the premier low-cost natural gas producing region in the U.S. In the last decade the region went from producing less than 1% of U.S. gas supply to about 30% and the economics and new pipeline capacity suggest that this percentage will continue to grow incrementally. It is a simple fact that cheaper energy saves people and businesses money. Affordable energy is a foundation for a successful economy. A recent report by Consumer Energy Alliance in Pennsylvania claims that low natural gas prices have saved residents and businesses $30.5 billion in the last decade. $13.3 billion was saved by residents and $17.2 billion was saved by businesses. That is about $400 per year per family for residents and even more for the companies they work for. A similar report for Ohio showed $40.2 billion in savings over the decade, $15 billion saved by residential customers and $25.3 billion saved by commercial customers. Some of those business savings certainly went into wages and jobs. Thus, in addition to the direct and ancillary jobs the oil & gas industry provides there are also jobs and better wages provided by energy savings by businesses. Businesses also have more money to invest in order to keep people working. Residential savings have a greater positive impact on the poor who spend higher percentages of their income on energy, heat, and electricity. Cheaper gasoline and diesel helped by American tight oil from fracked shale has a similar impact. The higher wages associated with the Appalachian natural gas industry also help to build up a local middle class. There is also massive investment underway and much more in the planning stages as part of the developing Appalachian storage and petrochemical hub that will be fed by local natural gas and natural gas liquids.

Environmental Risks Overstated

The Pennsylvania DEP has noted that more wellsite inspections have been conducted in 2017 and full compliance is at 95% which is at a maximum compared to previous years. (violations are not necessarily willful violations as some are due to accidents, misunderstanding of regulations, or outside contractor errors). PA’s Annual Oil & Gas Report also noted no direct impacts from fracking to water supplies although they of course acknowledge incidents of stray gas, also known as methane migration. Many other studies have shown no impact to water supplies. Recently, I was asked whether some low-income friends should lease their minerals as they were most worried about well water contamination. I indicated they should as the risk is low and they could really use the money. Other PADEP reports indicate no impacts to headwater streams, effective well integrity practices to prevent groundwater contamination, and two reports issued by the PA Dept. of Health suggest no negative health impacts from shale development. One was an air quality study in Washington County where shale development has been extensive and a widespread air monitoring network was set up. Monitoring air for VOCs, formaldehyde, ozone, carbon monoxide (CO) benzene, 2.5 particulate matter, and nitrogen oxide (NO2) showed no increases over comparable PA air quality and well below the national ambient air quality standards (NAAQS). Other studies showed similar results.

Anti-Fracking Activists Out of Touch with Reality

Anti-fracking activists continue to deny the clear benefits of fracking. As I mentioned elsewhere, one might call them ‘fracking benefit deniers’ in a similar fashion as some deride “climate deniers” which is a thinly veiled reference to the absurdity promoted by anti-Semitic “holocaust deniers.” There are still media sites like Eco Watch and DeSmog Blog that post any anti-fracking information and propaganda they can find, including every accident and every negative article. There are still ridiculous sensationalized headlines by these groups that distort scientific studies to fit their narrative. Far left politicians like Bernie Sanders, Dennis Kucinich, and others still call for nationwide or statewide fracking bans. Activists scientists are still supporting those efforts with misleading rhetoric. In some places businesses still openly display anti-fracking propaganda. Anecdotal accounts of people poisoned by fracking still occur and are collected and reported by anti-fracking activists. Anti-corporate law firms are still trying to enact local ordinances against oil & gas activity. Since as time has gone on there have been no widespread impacts one might think such activity would wane but the activists often cushion themselves with their own facts and narratives so the danger is still there for public outrage when accidents or negligence occur. For this reason and other reasons of public reputation many oil & gas companies are more vigilant about full compliance and developing cultures of compliance which is a win for everybody, except maybe the activists.

Decarbonization Still Happening and Natural Gas is a Part of the Picture

Of course, the economic and relative environmental advantages of fracking do not mean that a transition to carbon-free energy is not inevitable. Fossil fuels are still a finite resource even though we have found ways to produce more reliably and inexpensively and likely will continue to do so for a while. Wind, solar, and battery storage continue to improve incrementally and that is likely to continue as well. As time goes on, more data on climate may cement the more catastrophic predictions of climate change. If that happens, then decarbonization will be accelerated which will favor renewables. Even in that case natural gas will still play a big part as a partner to intermittent wind and solar. Utility executives are still committed to decarbonization and in most areas that includes building more wind and solar generation and battery storage. Economics (more and more as time goes on), customer expectations, and policy (incentives and subsidies) have driven and will continue to drive decarbonization, says Excel Energy planning executive, Jonathan Adelman. He states that in some places even now the incremental cost of renewables is cheaper than the embedded cost of fossil fuels, notably coal.

Ongoing Federal Monitoring and Studies on Fracking Impacts

Many studies of fracking impacts are ongoing at the federal level. The National Science Foundation has an ongoing study integrating food, water, and energy systems in the northern Great Plains where the population is low but energy and especially agricultural production are high. Both are water intensive. Other federal agencies such as the USGS, the EPA, and the DOE are investigating things like the composition of flowback and produced water (USGS), potential impacts from spills and gas migration on drinking water sources (EPA), and possible exposure routes of fluids and chemicals from wellbores and tanks (DOE). There are also well sites being used as 'testing laboratories' by the DOE where all systems are monitored including water use,  possibility of contamination, possible leaching of heavy metals and radioactivity of drill cuttings, etc.

References:

An Anniversary of History Being Made: The Birth of Modern Fracking – by David Bahnsen, in Forbes, Aug. 8. 2018

New EIA Data Show Shale Drove U.S. Energy Costs to Record Low Levels in 2016 – by Seth Whitehead, in Energy In Depth, Aug. 14, 20

Fracking, 10 Years Late: Its Benefits Far Outweigh its Risks – by Seth Whitehead, Op-Ed in The Washington Examiner, Aug. 28, 2018

Like That Cleaner Air You’re Breathing? Fracking Says, ‘You’re Welcome!’ – by David Blackmon, in Forbes, Sept. 5. 2018

Report: Pennsylvanians Saved More Than $30B Over Last Decade from Lower Natural Gas Prices – by Mike Larson, in Pittsburgh Business Times, Sept. 7, 2018

Consumer Energy Alliance – Everyday Energy for Pennsylvania, report https://consumerenergyalliance.org/cms/wp-content/uploads/2018/08/CEA-Pennsylvania-Report.pdf, Aug. 8. 2018

Pa. Agencies Find Shale Development Has Little Risk of Harming Public Health – by Nicole Jacobs, in Energy In Depth, July 24, 2018

Pa. Annual Oil and Gas Report: No Evidence Fracking Having Direct Impacts To Water Supplies – by Nicole Jacobs, in Energy In Depth, Sept. 5, 2018

Consumer Energy Alliance - The Benefits of Ohio’s Natural Gas Production to Energy Consumers and Job Creators https://consumerenergyalliance.org/cms/wp-content/uploads/2018/08/080718_OH-CFAE-Natural-Gas-Report_FINAL.pdf

Xcel Resource Planning Executive: We Can Buy New Renewables Cheaper Than Existing Fossil Fuels – by Juan Monge, in Green Tech Media, Sept. 11. 2018

When oil and water mix: Understanding the environmental impacts of shale development – by Daniel J. Soeder and Douglas B. Kent, in Geological Society of America, GSA Today, Vol 28, Issue 9, September 2018

The Water Footprint of Fracking: Probably Only an Issue in Arid Areas with Scarce Groundwater AND Immature Oil & Gas Water Management Systems and Practices: Also the Reasons for Increased Water Usage

The Water Footprint of Fracking: Probably Only an Issue in Arid Areas with Scarce Groundwater AND Immature Oil & Gas Water Management Systems and Practices: Also the Reasons for Increased Water Usage

A recent paper by researchers at Duke University emphasizes the increasing water usage and wastewater generation of fracking. The study designer and co-author, Abner Vengosh, was lead author in some earlier papers that were somewhat misleading and partially debunked about the extent and sources of methane migration early in horizontal well fracking history. Yes, water usage has increased quite a bit due to higher pumping rates (early on) and longer well laterals. However, there is no shortage of water in areas like the U.S. Northeast. Areas in the U.S. Southwest can be affected by water usage and water well drawdown. According to the paper (referenced below) the water usage per well in the Marcellus region only increased 20% from 2011 to 2016. Part of the reason for this small increase is that the region was at the time working toward the highest percentage of wastewater treating, recycling, and reuse. The Permian Basin region of West Texas had the highest increase from 2011 to 2016 (770%) in part due to longer wells being drilled requiring more water. The paper shows that both the West Texas Permian region and the South Texas Eagle Ford region show the most potential for both increased water usage and subsequently increased flowback and produced water.

Water management – both of freshwater draw and flowback and produced water is a big issue in oil and gas these days and there are many solutions coming forward. Texas has many saltwater injection wells capable of handling wastewater. I predict that as water reuse becomes more common there the increase will become less through time. However, anti-fossil fuel advocates like Climate Progress founder Joe Romm put their own spin on the Duke researcher’ paper. Note their headline involving the same paper: “Fracking is destroying U.S. water supply, warns shocking new study: Toxic wastewater from fracking jumps 14-fold from 2011 to 2016 — and it may get 50 times bigger by 2030.” He calls it a game-changing study but most reasonable people would see it as a manageable problem. Even Popular Science headlined their coverage of the paper to seem as if the increase of water per well was a big issue. Actually, there are two issues. 1) A well twice as long as another will use twice as much water, and 2) a well with more closely-spaced frac stages will use more water than one with further-spaced frac stages. Both of these things have occurred and have drastically increased the amounts of gas and oil extracted per well. The paper does not seem to mention point number 2, which mainly accounts for the strong increase in production per rig from late 2014 through early 2016. In 2011 the Permian region was just getting started and shorter laterals were drilled to test the viability and define the extents of the play. I speculate that this is a strong factor in the increase in the Permian as longer laterals with close-spaced frac stages were adapted quickly in the second half of the study period. This has also occurred in the Marcellus region and makes one wonder why they didn’t see a bigger increase of water usage there. As previously mention, perhaps the increase in water reuse in the Marcellus region (thought to be the highest of the shale plays) is a strong contributing factor as the amount of water recycled increased in that time period. Quite a bit of acreage in the more populated Marcellus area is constrained by lease boundaries so that even though wells got longer, on average the Permian area was able to increase well length, and thus water usage, faster. It is unclear sometimes in reading the paper and the reporting about it – whether one is talking about water use per well, which would be a function of longer laterals and more closely-spaced frac stages which means more frac stages per well and so more water usage per well vs. water use per foot, which is more a function of just more closely-spaced frac stages, regardless of length of well.

The Duke paper suggests that water usage per well and per foot drilled will continue to increase in the future. Well, water usage per well will likely increase for a few years (since the data they use is 2 years behind) as well lengths continue to increase but each play will have a maximum safe well length and it is thought that the longest current laterals are close to that max safe well length. I would guess 5-10 years  from 2016 we will begin seeing max avg. well lengths level out. Water use per frac stage is probably currently at optimum levels. Frac stage spacing is also close to optimum levels as getting closer will yield diminishing returns per stage. Therefore, it is likely that after max safe well lengths are worked out the water usage per well and water usage per foot will cease to rise.  

Wastewater management and recycling systems have become the norm in the northeast and other places. The industry has advanced in the last decade in handling the increased water volumes. There is room for improvement in efficiency of recycling. The paper also points out that coal mining is more water intensive than gas and oil drilling per energy unit and that coal burning is more water intensive than gas burning per unit of energy so any overall water usage increase is partially offset by producing and burning more gas relative to coal. The Duke authors also point out that “the overall water withdrawal for hydraulic fracturing is negligible compared to other industrial water uses on a national level…” The paper also rightly points out that water scarcity is nearly always a local issue so the arid west, particularly the Permian and Eagle Ford areas, are most vulnerable. I have heard that the state of New Mexico, part of the Permian Basin, is currently limiting water use for fracking in some areas. 

Many studies of fracking impacts are ongoing at the federal level. The National Science Foundation has an ongoing study integrating food, water, and energy systems in the northern Great Plains where the population is low but energy and especially agricultural production are high. Both are water intensive. Other federal agencies such as the USGS, the EPA, and the DOE are investigating things like the composition of flowback and produced water (USGS), potential impacts from spills and gas migration on drinking water sources (EPA), and possible exposure routes of fluids and chemicals from wellbores and tanks (DOE). There are also well sites being used as 'testing laboratories' by the DOE where all systems are monitored including water use,  possibility of contamination, possible leaching of heavy metals and radioactivity of drill cuttings, etc.

References:

The Intensification of the Water Footprint of Hydraulic Fracturing – by Andrew J. Kondash, Nancy E. Lauer, and Avner Vengosh, in Science Advances Vol. 4, No. 8, Aug. 15, 2018

Fracking is Destroying U.S. Water Supply, Warns Shocking New Study – by Joe Romm, in Think Progress, Aug. 17, 2018

Alarmist Headlines Obscure Context of Duke Study on Water Use and Fracking – by Dan Alfaro, in Energy In Depth, Aug. 17, 2018

New Fracking Wells are Using Many Times More Water Than Their Predecessors – by Kat Eschner, in Popular Science, Aug. 15, 2018

When oil and water mix: Understanding the environmental impacts of shale development – by Daniel J. Soeder and Douglas B. Kent, in Geological Society of America, GSA Today, Vol 28, Issue 9, September 2018

The Age of Superlaterals: Multi-Well Pads, Walking Rigs, High-Speed and Rotary Steerable Drilling, Zipper Fracking, Better Targeting and Target Maintenance, Synthetic Oil-Based Mud, and Tightly-Spaced Frac Stages with More Proppant Per Stage: Oil & Gas Drilling and Completion Innovations That Recover More Oil & Gas Per Well, Per Pad, Per Frac Stage, and Per Amount of Land Disturbed

The Age of the Superlaterals: Multi-Well Pads, Walking Rigs, High-Speed and Rotary Steerable Drilling, Pad Fracking, Better Targeting and Target Maintenance, Synthetic Oil-Based Mud, and Tightly-Spaced Frac Stages with More Proppant Per Stage: Oil & Gas Drilling and Completion Innovations That Recover More Gas & Oil Per Well, Per Pad, Per Frac Stage, and Per Amount of Land Disturbed

Improvements in well drilling and well completions have resulted in very significant efficiency gains over the last several years in unconventional drilling. This is typically the horizontal drilling and fracking in mostly U.S. shale plays that dominates new gas and oil production in the U.S. With the recent downturn in oil and gas from late 2014 through 2016 the need for cost-reduction was very strong. Now that oil, NGL, and natural gas prices have recovered and the industry along with them, the innovations are here to stay and continue to improve incrementally.

One way of measuring efficiency improvements used by the Energy Information Administration is what they call Drilling Productivity. This is measured in average gas and/or oil production per rig employed. Appalachian natural gas production per rig has increased 10-fold over the last 8 years. From the latest drilling productivity report for Appalachia it can be seen that production per rig quadrupled from Sept. 2012 to August 2016 as some of these improvements came to fruition. The increase has been fairly uniform overall but doubled from April 2015 to August 2016 and then dropped slightly due to the industry downturn before resuming increases.

Other ways of comparing well results include EUR (estimated ultimate recoverable production) per 1000 ft of lateral and production per frac stage. For new areas where little or no production is available there is IP (initial potential, or estimated rate) per frac stage. These numbers have been extensively used in company investor and analyst presentations. While pre-horizontal drilling used to be tabulated in cost per foot (CPF) it is now tabulated in cost per lateral foot (CPLF). Range Resources' Drilling VP Don Robinson notes that Range's CPLF has come down consistently over the last several years with longer laterals drilled faster with less down-time and costly accidents:

  

Superlaterals: In Appalachia and Elsewhere

Eclipse Resources has been the pioneer in superlaterals in the Utica-Point Pleasant Shale play in eastern Ohio. They have now drilled quite a few of these long laterals, although they do acknowledge that there will be a limit to how long laterals can go. EQT has also begun drilling long laterals of 15,000 ft or more in the Marcellus and Upper Devonian Burket in Pennsylvania. They plan to drill much of their laterals at these lengths where applicable. At the recent DUG East meeting there was a panel that discussed completions and long laterals. They touted the economic advantages of long laterals but also acknowledged that there were risks – typically drilling and casing issues. Eclipse VP of drilling and completions Oleg Tolmachev also gave a rundown at DUG East of their superlaterals. He noted that they now have 15 superlaterals with an average lateral length over 18,000 ft with the longest, the Purple Hayes, at 20,803 feet of lateral. The lateral part of the well was drilled in 13 days.

“We spread our fixed costs for things such as roads, vertical wellbore, pad size and surface facilities across the footage of the lateral,” Tolmachev said.

Also noted in the E&P article referenced below is the following:

“In the lateral section the proper rotary steering tool must be used to minimize horizontal doglegs. Mud rheology can improve the wellbore stability as well as the use of managed pressure drilling. In addition, the proper mud will also manage gas influx and prepare the well for “frac hits” and production interference.”

“To manage circulation, three mud pumps are suggested for the best circulation rates at total depth and split-string drill pipe is also used to maximize circulating rates and minimize friction losses.”

In mid-2017, Chesapeake announced completing a 17,000 ft lateral in the Eagle Ford Shale, the longest in that play. In 2018, Range Resources drilled two 18,000 ft laterals in the Pennsylvania Marcellus, the longest wells in the play thus far. Ascent Resources' longest lateral so far in the Utica is 16,500 ft. with plans to drill several laterals longer than 15,000 ft. Antero Resources drilled four wells with lateral lengths of 17,400 ft.

The record for the longest on-shore lateral now belongs to Conoco Phillips with their 21,478 ft lateral in Alaska’s North Slope, announced in April of this year.

There are limits to how long a lateral can go and they vary by formation, or rather by how deep the vertical section of the well is. This is due to the ability to drill and get casing to bottom, to deal with ever-increasing friction in longer and longer wells. I am guessing that circulating drilling mud and minimizing mud loss is challenging with 4 mile laterals which in the Utica make the entire measured depth closer to 6 miles - even with 3 mud pumps. Circulating cement might be challenging as well. 

Drilling Innovations

There are advances on both the well-drilling and well-completion side that have contributed to the efficiency gains. On the drilling side are the advantages of rotary-steerable drilling systems, better geo-targeting and target maintenance through geosteering, better mud systems such as synthetic oil-based mud that offers very good well-bore integrity, better mud pumping criteria, better solids control strategies, better bits, and better borehole management techniques. ‘Better’ for one formation or play may not be the same for another as many of the drilling tweaks are play-specific. Each play goes through a series of learning curves that lead toward ‘optimization,’ which usually refers to the highest efficiency of any technology. Walking rigs are another innovation. These drilling rigs can move from one borehole on a pad to another – typically about 20 ft away – very quickly to minimize time between wells. Multi-well pads have been the norm for several years now and now super-pads are being built targeting multiple formations. Targeting multiple formations allows the laterals to be spaced closer together. This does, however, require better and more frequent ‘anti-collision’ analysis. Super-pads may also be more of a nuisance for anyone living nearby so where they are put needs to be considered. Another drilling innovation has been to begin curve-building at much higher depths, allowing for smaller borehole kinks, ie. ‘doglegs,’ and better management of multiple wells on a single pad. Wells may be 2D, curving in one direction only, or 3D, swinging out to avoid other wells on the pad and to achieve desired spacing between laterals, and they may swing behind for a while, adding length to wells where length is constrained by acreage boundaries. 

Robinson, in the Journal of Petroleum Technology article referenced below also note that longer laterals require rig adaptations such as mud pumps rated for 7500psi rather than 5000psi, 2000hp pumps rather than 1600hp pumps. The added pressure is required to clean the hole and helps power the rotary steerable tools. Stronger top drives, more rack back capacity for drill pipe, and additional power generation are other rig adaptations. Better monitoring of mud properties and shapes and sizes of drill cuttings are also helping drilling adapt to longer wells.  

Multi-Well Pads and Super-Pads

Multi-well pads are now industry-standard. They lower costs in a number of ways. Some are: less entrance roads, more accommodating for frac-water delivery pipelines and frac-flowback water pipelines, sharing of some production equipment, easier to tie-in multiple wells in the same time frame, evaluating data on a per pad basis, less time and money spent in rig and equipment moves, ability to frac wells in sequence – zipper frac, and ability to drill and set conductor casing very efficiently.

EQT has recently permitted and begun work on a 40-well pad targeting wells in the Ordovician Utica-Point Pleasant, the Middle Devonian Marcellus, and the Upper Devonian Burket/Geneseo. However, they note that they may not drill all the wells on these superpads. So far, the most wells they have drilled from a single pad is 22 (at least as of Jan. 2018). They are averaging 17 or 18 wells per pad in addition to drilling long laterals of 15,000 now routinely. In the Permian Basin of West Texas, Encana has built a pad for 64 wells!

EQT has been drilling 5 or 6 wells on a superpad, then completing them and producing them for a while till their high flush production declines a bit before going back to drill the next set. This is done so that pipeline size can be optimized for each packet of wells rather than being undersized for flush production then oversized as gas production declines. Range Resources noted that they were building pads to accommodate 20 wells and that they could return to drill the next set of wells when ready or wait until gas prices or NGL prices are adequate if necessary – so it options them for quick reaction to market forces. An example below shows an EQT pad with 22 wells.

Rotary Steerable Directional Drilling Systems

Rotary Steerable Drilling Systems offer some advantages over traditional mud motors, including faster drilling and lower dogleg severities. The lower doglegs are important for longer laterals, likely essential for superlaterals, since getting casing to the toe-end of the laterals can be an issue. Too many, too big, and too tightly-spaced doglegs can also negatively affect drilling. Another advantage of rotary steerable systems is that their survey tools that measure orientation and gamma ray probes of the rocks are closer to the bit so that steering decisions can be closer to real-time than in conventional ‘bottom-hole assemblies’ where they are farther back on the drill string. This is especially advantageous in areas where rocks are highly folded. However, conventional mud motors may be quite adequate and more economic in several areas with less geological variation and in shorter laterals.  

High-speed drilling in general has been allowed by better drill-bits, better mud system management, better directional drilling, and better geosteering. Several rigs have entered or frequent the "mile-a-day" club. Appalachian Basin driller Antero Resources notes they drilled a record 8206 ft in 24 hours and their avg. footage drilled in a day ticked up to 4700ft. The overall trend is toward faster drilling or at least reasonably fast drilling. There can be dangers when drilling too fast as the mud system and pump volumes and rates need to be adequate to clean the hole and the jets jetting fluid from the bits need to be adequate to clean the bit. MWD sampling rates have to be frequent enough to get a detailed gamma ray log. 

Targeting and Geosteering Strategies

Geosteering has played a role in increasing drilling productivity. The first step is finding the best zone to drill laterally in each play. This may involve geochemistry, gas-in-place analyses, TOC analysis, geomechanics, avoiding zones with high clay content, or favoring zones with higher silica content or a certain type of carbonate content. Typically, the silica-rich and sometimes carbonate-rich zones are more brittle and frac-able while the clay-rich zones are less brittle, more ductile, and so have less frac-ability. Once the preferred zones are determined and tested through drilling and production then the goal is to stay in or very near those zones in rocks that may be subject to folding, faulting, depositional thinning, and other facies variations. Being in these best zones often means more of the preferred rock in terms of both gas content and the ability to initiate fractures is accessed via the borehole. This has been termed ‘primary reservoir access.’ Production data have shown that “geosteering efficiency,” or the ability to stay in zone does indeed correlate to better production. That means that increasing geosteering efficiency, or primary reservoir access, even by a few percentage points can have a significant effect on production and profitability. In faulted and highly folded areas, most geologists and engineers think that the tectonics negatively affect production mainly by causing the induced hydraulic fractures to propagate into the existing faulted and naturally fractured rock rather than cracking the rock anew in a more consistent and far-reaching manner. This is still an open question as some still like naturally-fractured areas but all agree that large faults are to be avoided – additionally since staying in zone in those areas is often difficult or impossible. Successful geosteering requires coordination between geosteerers, drilling engineers, and directional drillers. It requires vigilant data interpretation in real-time in a dynamic system – rock dip orientation variability. It also requires the ability to know how drilling and surveying can affect the data. It involves frequent qualitative decisions based on mostly quantitative data interpretation and eliminating competing interpretations. With effective geosteering it is possible to optimize primary reservoir access by placing and maintaining the wellbore in small target intervals.

Completion Innovations

On the completion side there is possibly the largest effect on well-production – proppant loading. This is simply how much proppant can be pumped into the induced fractures during hydraulic fracturing operations. Proppant is typically sand of specific and uniform sizes that is pumped in order to hold open the induced hydraulic fractures. Studies have indicated that proppant placed per frac stage probably has the most positive effect on production per cost. Different companies have different sand recipes and pumping schedules for each frac stage that they tweak. More closely-spaced frac stages has also lead to very significant well-production increases. Frac stage spacing is probably now optimized as much as it will be due to diminishing returns on closer and closer spacing. Ascent Resources notes that they use 150ft stage spacing in their gas wells and sometimes closer for liquids. They proppant load at 1500-3000 lbs per foot. They also mention spacing perf clusters 30-35 ft apart. Antero Resources notes their average proppant loading at 2000 lbs per foot. Well results are getting bigger with flush production and pressure lasting longer. 2-2.5 BCFeq/1000ft of lateral is the EUR range in the core areas of Marcellus and Utica with some even exceeding 2.5 BCFeq/1000ft of lateral.

The biggest gains in EIA’s drilling productivity graph have likely come from closer spacing and more proppant loading between April 2015 to August 2016 when the wells with closer stage spacing and more proppant per stage first came on-line en masse. Another completion-side innovation has been pad fracking where wells on a pad are hydraulically fractured in sequence. So-called ‘zipper fracturing’ has been the most adopted technique. Diversion, or diverting frac fluids to perforation clusters, is also being evaluated. This would allow more specific proppant placement and in theory could get as much stimulation over more rock – according to the DUG East discussion– making say a 300 ft stage spacing as effective as a 150 ft stage spacing, which could save significant completion costs while stimulating an equivalent amount of rock – in theory, as these techniques are still being evaluated. 

Zipper fracturing allows pad wells to be fracked simultaneously so that while one process is going on in one well another may be going on in another well, thus optimizing efficiencies. Fracs can be monitored and 'mapped' with microseismic and fiber optics to determined where the energy of each stage went in 3D space.

Also discussed at DUG East were “frac hits” where hydraulically fracturing a “child well” (basically an infill well) causes changes in pressures and production in a “parent well” (basically a pre-existing legacy well). It has also been called “frac-bashing!” Sometimes a child well may stimulate a parent well and sometimes (probably more often) it may make it perform worse. It is likely that each play is different in this regard. “Pressure rejuvenation of parent wells” may become a more applicable technology as it develops. The jury is still out on the economics of “re-fracking” old wells that used less effective stimulation techniques, but certain candidates are probably ideal for it. Other techniques being explored include the use of highly durable ceramic proppant which is more expensive but may be worth it for certain plays with high reservoir temperatures and pressures. 

More proppant per frac stage also means more frac sand, a lot more. E & P Magazine, in an article referenced below shows how efficiently getting the large mount of frac sand to well pad locations for simultaneously fracking multiple wells through zipper fracking can save money and time (time is money on completion jobs as any time lost waiting can be very expensive). Again, the goal is optimization.

References:

Superlaterals: Going Really, Really Long in Appalachia – by Larry Prado (ed.), in Hart Energy E&P Magazine, July 2, 2018

Chesapeake, Laurel Mountain, BHGE Discuss Completions in Appalachia – by Velda Addison (Ed.), in E&P Magazine, July 10, 2018

ConocoPhillips claims North American record for horizontal drilling – by Alex DeMarban,  in Anchorage Daily News, April 23, 2018

These days, oil and gas companies are super-sizing their well pads – by Anya Litvak, in Pittsburgh Post-Gazette, Jan. 15, 2018

Shale Oil: The Arrival Of Super-Laterals Is Just A Matter Of Time – by Richard Zeits, in Seeking Alpha, June 30, 2017

Drilling for Miles in the Marcellus: Laterals Reach New Length - by Range Resources (Don Robinson VP of Drilling), in Journal of Petroleum Technology, Aug. 8, 2018

Efficiency Gains Help Independents Find Success in Marcellus, Utica Shale - by Al Pickett, in American Oil & Gas Reporter, August 2018

Optimizing Frack Sand's Last Mile - by Zach Carusona, Sand Box Logistics, in Hart's E & P Magazine, Aug. 15, 2018