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

The Continued Prevalance of Black Lung Disease Among Coal Miners: A Preventable Tragedy and Yet Another Reason to Move Away from Coal

The Continued Prevalence of Black Lung Disease Among Coal Miners: A Preventable Tragedy and Yet Another Reason to Move Away from Coal

A graphic on the Mine Safety and Health Administration website notes that since 1968 there have been 76,000 deaths from Black Lung disease at cost of $45 billion in Federal compensation. Black lung includes a series of maladies caused by long term chronic exposure to coal dust and silica dust, which scars lung tissue. This black particulate matter can coat the lungs causing difficulty in breathing and eventually death. The deadliest form or advanced phase of black lung is a malady called progressive massive fibrosis (PMF) or complicated black lung. The National Institute Occupation Safety and Health (NIOSH) announced in February that there have been 416 confirmed cases of PMF in central Appalachia from 2013 to 2017. Since that study 154 new cases have been confirmed. That is a huge uptick and it shows that the disease is not slowing down as it was thought to be in the 1990’s. Out of 50,000 coal miners still working, 1%, or 1 out of 100 (of that total as some of those w/PMF may no longer be working) have the worst form of black lung and presumably many more have lesser versions heading toward PMF. That is concerning. Perhaps most concerning is that 5% of all veteran miners and 10% of those with more than 25 years of mining experience in central Appalachia have PMF which is the highest level ever recorded. More than 20% of miners in Appalachia have been diagnosed with some form of the disease. That is rather astounding.

The new data of rising PMF black lung cases suggests two things to some health researchers: 1) it would be considered a serious health crisis if it occurred in other industries, and 2) the new data show that dust control regulation and/or enforcement and/or fines have been inadequate.

The Coal Mine Dust Rule was first put in effect in 2014. The Mine, Safety, and Health Administration (MSHA), a branch of the U.S. Dept. of Labor, explains this ‘respirable dust rule.’ First implemented in August 2014, it required an initial year of continuous dust sampling in mines and certification every three years of samplers. This showed that compliance with the planned reductions was achievable. Phase III went into in August 2016 and requires lower limits for coal mine dust in the mines and at air intakes. The limit for dust in the mines dropped from 2mg/cubic meter to 1.5 mg/cubic meter. The initial proposal was to drop it to 1 mg/cubic meter as recommended by NIOSH. Negotiations over 3-1/2 years with coal producers and politicians led to the compromise. This was the first time there was any implementation of a regulation against coal dust for 45 years. The previous law in 1969 made eliminating black lung a national goal. The rate of contracting the disease did drop in subsequent years as better mining ventilation systems became standard, water-spraying dust control was widely implemented, and monitoring was required. The level of black lung was cut by nearly 60% from the 1970’s to the 1990’s. That was a clear regulatory success in terms of health outcomes. Then the level flattened and has been back on the rise in recent years. In studies, a rise was first noted in 2007, a general rise was noted in 2012 and a bigger rise in 2016.  

The MSHA calls the respiratory dust rule “a historic step forward in the effort to end black lung disease.” NIOSH researchers stated that “Enhancement and diligent enforcement of the 2014 standards remains critical for reversing these trends” The mining industry strongly opposed the rule with the National Mining Association and coal producer Murray Energy filing lawsuits. Murray Energy claimed that MSHA “clearly seeks to destroy the coal industry and the thousands of jobs that it provides.” However, the Trump MSHA with former coal executive David Zatezalo now in charge, seeks to ‘reform’ the rule, first gathering their own data in support of their presumed idea of reducing required sampling frequency and “accommodating less costly methods.” He insists they do not seek to roll back the rule, only to tweak it, although it has been labeled by MSHA as a ‘deregulatory’ action which has raised eyebrows. In April Trump’s MSHA submitted the draft request for information about the rule titled “Regulatory Reform of Existing Standards and Regulations: Retrospective Study of Respirable Coal Mine Dust Rule”

In 1998 there was an expose’ by a Louisville newspaper that found extensive cheating on mine dust samples by coal producers in Kentucky. A few years ago there was a case of admission of guilt in cheating on water samples taken for coal companies in West Virginia. These and other cases show that there is a need for regulatory enforcement. The same paper reported in 2007 on the initial resurgence of black lung. More recently, there have been several indictments for people from a few mines in Western Kentucky where some whistleblower miners told of routine manipulation of dust samples at the threat of harassment and/or job loss. This was at two Armstrong Coal mines between 2014 and 2017, Armstrong Coal has since gone bankrupt. Those charged include a section foreman, a safety director, and a superintendent. Armstrong Coal is named as an "unindicted co-conspirator." One might speculate that there was some 'pushback' against the new federal rule at least at those mines. Of course, when one company or group in a company conspire to avoid implementing compliance to a regulation and get caught then it makes all those who do comply look bad as well in a sense. In the case of the very well known dangers of black lung the cheating seems particularly devious. The Ohio Valley Resource article referenced below is a good summary of the case.

Other expose’s have shown doctors retained by coal companies had sought to limit black lung benefits to miners and even now there are severe limits in choosing doctors in Kentucky. The requirement is for the disease to be diagnosed only by a small group of certified pulminologists, lung specialists, rather than radiologists. Radiologists day they are perfectly qualified to diagnose the malady. This means that it could take over a year for people to even be seen by the lung specialists. Since early detection is key to mitigating the effects of black lung, this is a delay that certainly could negatively affect health outcomes.

All the data suggest that black lung can be significantly reduced – simply by adequate regulation, enforcement, and corporate accountability through fines and inspections. Regardless of the economics of coal producers, at 76,000 dead, over 10,000 ill, and $45 billion and counting  - this is a no-brainer. 

Update: Dec. 19, 2018: According to a news segment by NPR yesterday which will be seen in a Frontline/NPR TV special next month, there is some additional very interesting info. In recent years as coal seams are mined out there has been more cutting through non-coal rock, rock containing high amounts of silica dust. Silica dust is strongly suspected of being much more damaging to lungs than just coal dust. The Obama-era regs sought to address silica dust by addressing overall dust rates, which would be an improvement but not a drastic one for overall exposure to black-lung causing dust. The miners interviewed noted that this “cutting rock,” also known as “slope mining” has definitely increased and so too has the silica dust to which they were exposed. Trump’s new MSHA chief has publicly acknowledged that silica dust is suspected to be the culprit in increased black lung but also has privately said in contradiction that the link is not yet proven. The silica dust is regulated by other regulatory agencies, particularly OSHA. Other industries regulate silica dust via OSHA but the mines have kept the MSHA regs. A big factor that may miss the increased exposure is that sampling rates are probably inadequate. Even though mines now use third parties to do the sampling the rates of sampling are likely inadequate. The miners that operate the mining machines cutting rock also say that the dust is so heavy that it clogs up dust masks making it hard to breath and some mines don’t even require dust masks. Mine vents may be seen by the mine operators to be enough to mitigate the problem, but this is fairly obviously not the case. This latest increase in black lung and PMF likely due mainly to silica dust has been accurately described as a regulatory failure. Basically, with the increase in slope mining and the subsequent production of silica dust, “putting miners back to work” basically means hastening their suffering and death.

References:

Trump Wants to Weaken Coal Miner Protections as Black Lung Makes a Comeback – by Mark Hand in ThinkProgress, July 20, 2018

Black Lung Rate Hits 25-Year High In Appalachian Coal Mining States – by Howard Berkes, in NPR.org, July 19, 2018

Respirable Dust Rule: A Historic Step Forward in the Effort to End Black Lung Disease – by U.S. Dept. of Labor – Mine Safety and Health Administration (MSHA) (website) – 2014-2017

Black Lung Study Finds Biggest Cluster Ever of Fatal Coal Miners' Disease – by Howard Berkes & Adelina Lancianese, in NPR (All Things Considered) – Feb. 6. 2018

A Scourge for Coal Miners Stages a Brutal Comeback – by Ken Ward Jr. – in Yale Environment
 360, Nov. 11, 2014.

Federal Prosecutor Charges Coal Company with Faking Dust Samples Amid Black Lung Surge - by Jeff Young and Becca Schimmel, in Ohio Valley Resource, July 11, 2018

NET Power, Supercritical CO2 Technology, and the Development of the First Allam Cycle Natural GAs Power Plants: Featuring Carbon Capture, No Pollution, and Comparable Efficiencies to Existing Combined-Cycle Gas Plants

NET Power, Supercritical CO2 Technology, and the Development of the First Allam Cycle Natural Gas Power Plants: Featuring Carbon, No Pollution, and Comparable Efficiencies and Costs to Existing Combined -Cycle Gas Plants

Durham, North Carolina company NET Power announced a few weeks ago that they fired up their new $140 million 50MW test plant in LaPorte, Texas that runs on natural gas and captures the CO2 at no additional cost to other modern gas plants when done at scale. This is a big deal, possibly a very big deal. It is good for natural gas. It is good for decarbonization. It is good for pollution abatement. It is good for electricity consumers. It is good for people who live nearby who otherwise might be close to a major pollution source. This is likely to be a major victory for carbon capture technology. The main limiting factor to scaling this technology is the need for sequestration and/or to sell the by-products – mainly CO2, nitrogen, and argon. Oil companies purchase CO2 for CO2 flooding to recover oil and related plastics companies use it in making ethylene. Another advantage of these types of plants is that they have a smaller physical footprint than current natural gas combined cycle plants. NET Power’s parent company 8 Rivers Capitol is funding ongoing tech development, Exelon Generation is operating the plant, and Toshiba is working on turbine development. The plants also use far less water for cooling and could even be air cooled if necessary. They think that they will surpass the economics of a conventional modern combined cycle gas plant when they scale up, with the 30^th plant (presumably 300MW).

Supercritical CO2

The key to the plant’s function is supercritical CO2, which is CO2 that is heated to a certain temperature (31.1 deg C – a hot day in Phoenix) and pressurized to 7.39 megapascals. This makes the CO2 expand like a gas but flow like a liquid. Liquids can be pumped. The CO2 is compressed, pumped, and guided to spin a turbine. It is compressed to the needed pressure then pumped since pumping requires far less energy than compression. That is one key to its lower costs. It is the pressurized supercritical CO2 (SCO2) itself that runs the turbine.

Oxyfuel Combustion

Like combined-cycle gas plants the exhaust from combusting the gas in near-pure oxygen runs a turbine (here by heating CO2 to run the turbine), but instead of the second cycle being still-hot exhaust heating steam to run a second turbine the second cycle uses the waste heat to reheat the next batch of CO2 so that the heat is basically recycled. The plant also relies on oxyfuel combustion, or oxy-firing. This involves burning in pure oxygen. It was tried in the past in coal projects with limited results but works better in natural gas combustion, presumably due to less impurities in gas relative to coal. Using it for coal also requires a desulfurization system and generates waste in the form of sulfur and heavy metals. Oxyfuel combustion has been in common use for some time in other industries such as aluminum, steel, and glass. Nitrogen, which makes up over 70% of air, is removed. Another problem with coal is the ash it generates which gets sticky and is hard to handle. It is oxyfuel combustion that causes the waste stream from the combustion to be basically pure CO2, with magnitudes less impurities than a traditional combustion system. This makes carbon capture vastly easier and cheaper.

The Allam Cycle

UK engineer Rodney Allam is credited with the invention of the Allam Cycle. Allam has defined it as “a high-pressure, highly recuperative, oxyfuel, supercritical CO2 cycle.” The combustible mix by mass is 94% CO2, 4.75% oxygen, and 1.25% natural gas. The pressurized CO2 runs the fluid turbine (different from a steam turbine). Apparently, much of the CO2 can be reused (thus the term “highly recuperative”), some water is condensed out, and some 90+% pure CO2 (considered a pipeline-quality CO2 product) is ready for utilization or sequestration. It is unclear just how much CO2 is used up in the process and how much is produced as a by-product that must be utilized and/or sequestered. Allam notes that the process is not “parasitic, “or added on, as are all other conventional carbon capture technologies. He describes it this way in the 2013 Modern Power Systems article referenced below:

“NET Power turns the CO2 problem into the solution by exploiting the special thermodynamic properties of carbon dioxide as a working fluid. This avoids the energy losses that steam-based cycles encounter as a result of heat loss inherent in the unavoidable vaporization and condensation of water. In the process, NET Power generates - at no additional cost - a high-pressure, high-quality CO2 byproduct that is ready for pipeline removal.”

The process is termed “highly recuperative for a number of reasons: 1) much of the CO2 is recycled, 2) waste-heat from the air compressors of the cryogenic air separation plant associated with the oxy-combustion system (oxy-combustion is normally much more parasitic) is recycled to reheat the recycled CO2 – thus the heat-exchange process is highly efficient , 3) the energy savings from running compression to running pumps as the CO2 gets into a supercritical state, and 4) the CO2 is removed from the recycle flow at high purity and at pressures which can flow in a CO2 pipeline – it is both pipeline quality and pipeline ready.

Of course, the projects will be initially confined to places where the extra CO2 can be used which requires both a market for the CO2 and some CO2 pipeline infrastructure. Thus, it is likely to be confined to projects near major secondary oil recovery operations. He also notes that Toshiba is well-positioned to build the turbines required as they have the expertise in high pressure turbines, materials, and manufacture. The NET Power cycle systems are cheaper due to smaller footprint (in part due to higher pressures) and the lack of a need for smokestacks and emissions control systems. This saved cost is partially offset by NET Power’s requirements for a cryogenic air separation unit and a heat exchanger block.

Allam also mentions the NET Power cycle as a ‘platform’ that can be used for other processes such as a coal plant, LNG regasification facilities where it could increase efficiencies, hybrid concentrated solar-natural gas plants where it could increase efficiencies, by superheating steam at greater efficiencies than current in steam cycle turbines, and direct link-up to secondary recovery of oil where associated gas could be the combustible source. He also notes that the NET Power cycle can be utilized for coal just as readily and this could be useful for countries reliant on coal like India and China, although it is unclear what they could do with the excess CO2. 

Marketing CO2 and Other Gases

Finding a market for the captured CO2, nitrogen, argon, and a few other gases is a current focus. Power plants near oil fields could provide CO2 for enhanced oil recovery. The pure CO2 could even be used as a source to make gasoline or ethanol as analyses show these new processes to be economically viable at scale, especially CO2-to-ethanol. Of course, the extra CO2 could also be sequestered which would render the projects less economic and perhaps uneconomic. Perhaps they could even send some to Europe who has a current shortage of food-grade CO2 for things like carbonated beverages – although it is a temporary shortage due to plant maintenance! I wonder if CO2 in whatever state could also be utilized for energy storage – of the compressed air type. Indications are that the CO2-to-ethanol chemical reaction has very low energy input requirements and could very well be developed for energy storage, especially of intermittent renewables in times of overgeneration. Carbon capture, utilization, and sequestration (CCUS) has been at an economic standstill for some time since critics have argued that renewables, especially wind, are cheaper to deploy without CCUS than fitting fossil fuel plants with CCUS. The Vox article explores the problem of what to do with the CO2 and who pays for its sequestration. If the plant pays then the economics go way down. If the public pays then it becomes a fossil fuel subsidy. Of course, if there is a taker or buyer then the economics stay the same or get better.

The Current State of Carbon Capture, Utilization, and Sequestration (CCUS)

According to the article referenced below about the new clean energy incentives bill signed by Trump:

“Currently, there are 17 large-scale carbon capture plants in the world, sequestering 40 million metric tons of carbon dioxide in total—about 0.1% of total global emissions.”

That is a dismally small amount and critics probably correctly point out that CCUS seems unlikely to make a major impact on carbon emissions, especially in the near-term, as the costs have been consistently too high. The International Energy Agency suggests that by 2050 the global need for CCUS will be for 6 billion metric tons to be diverted from the atmosphere – or about 15% of emissions. This will be unlikely to happen without efficiency, cost, and technological improvements.  

Public perception of CCUS has waned over the years as the technology has stagnated. With wind and solar an added advantage is companies and residents that want zero or low emissions technologies. It is unclear if and probably unlikely that low-emitting tech that still uses fossil fuels will be as warmly welcomed and pursued in things like power purchase agreements. Thus, I doubt companies like Google, Amazon, or Facebook, would embrace the tech over wind and solar for their data centers, for example.

US DOE Energy Research Contributes to Technology Solutions

The National Energy Technology Laboratory (NETL) is involved with several research projects utilizing supercritical CO2 as well as turbine development, carbon capture, and sequestration. They are involved with R&D in several SCO2 cycles and turbomachinery in their Advanced Turbines Program. Their current projects include working with what’s called the Brayton Cycle which is a closed-loop system that is also non-condensing. The Alam Cycle involves condensing out water but could run without doing so at additional loss of efficiency – so added cost. The Brayton Cycle and other SCO2 cycles may work better with oxy-combusted coal. A 10MW natural gas test plant of the Brayton Cycle will open in Texas in 2019. Other SCO2 projects include ‘indirect firing’ which utilizes turbine waste heat to heat SCO2 in a conventional Combined Cycle Gas Plant steam cycle for a 2-4% increase in efficiency for little cost. Other projects involve converting waste heat from turbines and/or engines to heat SCO2 for a 20% increase in efficiency at a small scale. In the Netherlands Statoil, Mitsubishi, and other companies are working on a combined cycle gas plant that burns 30% hydrogen for a 10% reduction in emissions, although that project does not use SCO2 or oxyfuel combustion. Sequestration and utilization of CO2 also require transportation to point of use or sequestration, either via truck or pipeline so that is another area of expense and research. Obviously, being close to area of utilization and/or sequestration is an economic advantage.

There are also other incentives including a recently passed federal law that gives tax credits of $50 per metric ton of CO2 buried or $30 per metric ton of CO2 captured and used for oil production. These are the 45Q tax credits and plants beginning construction before 2024 are eligible and credits can be taken for 12 years.

References:

That Natural Gas Power Plant with No Carbon Emissions or Air Pollution? It Works: The Carbon-Capture Game is About to Change – by David Roberts, in Vox, June 1, 2018

This Natural Gas Plant Could Be A Big Breakthrough – by Nathanael Johnson, in Grist, May 31, 2018

NET Power Achieves Major Milestone for Carbon Capture with Demonstration Plant First Fire – Cision PR Newswire, May 30, 2018

This Power Plant Runs on CO2:  Carbon Capture Costs Nothing in NET Power’s New Plant, Which Uses Supercritical Carbon Dioxide to Drive a Turbine – by David Wagman, in IEEE Spectrum, May 30, 2018

Winner: Restoring Coal’s Sheen: Swedish Energy Company Takes a Novel Approach to Carbon Capture – by William Sweet, in IEEE Spectrum, Jan. 1, 2008

Supercritical CO2 Turbomachinery: Technology Development for Supercritical Carbon Dioxide (SCO2) Based Power Cycles – by National Energy Technology Laboratory (NETL) – website

NET Power’s CO2 Cycle: The Breakthrough that CCS Needs – by Rodney Allam, in Modern Power Systems (modernpowersystems.com), July 2013

Trump signed a landmark bill that could create the next big technologies to fight climate change – by Akshat Rathi, in Quartz (qtz.com), Feb 9, 2018

Natural Gas Pipeline Explosions: Can They Be Prevented? Can Risk Be Minimized?

Natural Gas Pipeline Explosions: Can They Be Prevented? Can Risk Be Minimized?

The recent explosion of a TransCanada pipeline on Nixon Ridge in Marshall County, West Virginia begs some obvious questions and answers. When the pipeline was first placed in service less than 6 months ago, a TransCanada spokesman stated:

“We’re looking forward to generations of safe operations,” he added. “This is truly a best-in-class pipeline and we look forward to many years of safe, reliable, and efficient operation on behalf of our customers.”

-TransCanada Scott Castleman, 6 months ago in January.

The pipeline exploded in the first week of June just after 4 AM in a fireball fed by pressurized gas that could be seen for up to 20 miles away. Although that pipeline was shut-in as soon as possible the fire in the surrounding countryside burned for another hour or so, singing several acres of forest. What happened? The cause of the explosion is of course still under investigation. Corrosion is often the culprit in pipeline leaks and explosions in old pipelines, but this is a new pipeline presumably with standard anti-corrosion measures built in.

Chemist Richard Peekema notes that although the National Transportation Safety Board (NTSB), which investigates pipeline explosions, has determined that many are caused by mechanical failure of defective pipe, one might also conclude that they are caused by “explosive ignition of accumulated gas leaks from pipeline defects into surrounding air spaces.” This assumes that the pipes leak first then explode. An explosion requires two things: a leak of gas and an ignition source or spark. Other potential causes are improper installation (usually ineffective welding), excavation that disturbs a pipeline, and ineffective safety equipment. An explosion can become far worse if safety valves to shut off compromised pipelines are not there or are defective. Adequate leak detection and repair (LDAR) is very important for preventing potential explosions.

Newer high volume and high-pressure pipelines may cause larger explosions, higher flames, and larger ‘incineration zones’ around the explosion. This is one argument environmentalists use against these large high-pressure pipelines. If the zones of incineration from a potential explosion are larger then this suggests that setbacks from homes and other structures should be larger as well. I live about 500-600 ft from a transmission pipeline, so I wonder what the incineration zone would be here. Explosions may lead to fatalities, injuries, property damage including houses and structures burning down, and forest and brush fires. Often people are evacuated during an incident.

Statistics from the Pipeline and Hazardous Materials Safety Administration (PHMSA) show that in the U.S. in the last 20 years (1998 through 2017) there have been 807 serious pipeline incidents (+40 per year on average), 306 fatalities (+15 per year on average) and 1262 injuries (+63 per yaer on average). Although the number of incidents has dropped slightly over the time span the number of fatalities and injuries has remained fairly constant. Thus far, there is no evidence that there are more incidents, fatalities, or injuries since the advent of “fracking” and with more high-pressure, high-volume transmission pipelines. Some pipeline incidents are caused by third party excavation so this does not just reflect just natural damage or leaks due to faulty installation or welding. Both the PHMSA and the National Transportation Safety Board (NTSB) investigate pipeline ruptures and assess fines.

Wikipedia has an extensive list of pipeline leak, spill, and explosion incidents in the U.S. The U.S. has by far the largest network of natural gas, oil, gasoline, natural gas liquids, and jet fuel pipelines in the world. They count about 3200 significant or serious pipeline accidents since 1987. That averages to over 100 per year. These include oil and other liquids pipelines, compressor-station incidents, excavation damage, and distribution lines (distribution lines are small but urban ones can be extremely old and unsafe - some made of cast iron – many currently being replaced) so do not reflect just natural gas events. According to Wiki the causes of pipeline leaks and ruptures include bad welding, foreign material contamination into a weld, cracked pipe due to manufacturing defects, cracked pipe at a bend in pipe, external corrosion, internal corrosion, a corrosion crack at a weld, gasket failure, valve failure, external bacterial corrosion in wet shale, environmental cracking, dented pipe, excavation, mismatched pipe, landslides, and even pipe thought to be damaged in transport. Contributing factors have included rocky backfilling, not enough inspection and pigging, lack of external coating on old pipes, inadequate past repair, landsliding, and other earth and soil movement. Pressure testing with nitrogen can also cause pipe bursts but not explosions.

Pipeline “smart pigs” are used to inspect internal and external irregularities in pipes and welds. They can measure degree of internal or external corrosion and corrosion pitting. Some old pipes do not have external coating that protects against corrosion. Some of those have been ordered to be replaced. These days there is cathodic corrosion protection on new pipelines and some older lines are dug up and equipped with it. Pigging operations can also be dangerous if a pipe has a pre-existing leak and people have been killed during pigging.

If a pipeline accident were to occur resulting in significant loss of life due to the line being to close to people and habitations then public outcry might change and setback requirements (which may vary by state but I’m not sure) would likely be increased. There seems to be no indication thus far that high-pressure lines and those with larger volumes are more likely to explode. The bigger pipes have thicker walls and are pressure tested before being placed in service. Environmentalists against pipelines have jumped on the danger of big high-pressure lines carrying “fracked gas” (as if it were different from non-fracked gas – anyway most gas is now fracked gas and that will increase).

I wonder what the likelihood would be of say a mile section of pipeline exploding. One might simply divide the number of explosions by the number of miles of pipeline. The PHMSA lists that there are 300,635 miles of transmission pipelines in the U.S. (as well as 927,011 service miles, 18,358 gathering miles, and 1,308,665 distribution miles – so 2,554,668 miles overall) and we assume about 50 transmission line explosions per year (guesstimate – probably less actually), then there is about a 1 in 700 chance that a pipeline will explode in a given year within about a mile from anyplace. If incineration zones are 500-1500 on avg. (another guess – say 1000ft avg) then that means that about 1/5 or 20% of the section within each mile will be in an incineration zone. This suggests that the risk of a section of pipeline being in an incineration zone is about 1 in 3600 in a given year. If we extrapolate that to a 30-year period that would be 1 in 120 so less than a 1% chance that a given section of pipeline will be part of an incineration zone in a 30-year period. So, the overall risk is small, but the results could be catastrophic. One might say that the risk of getting in a car accident is greater, probably much greater, than having an explosion occur nearby and certainly very far greater than getting hurt in one. Even so, it is possible. These explosions happen and can be disconcerting and possibly horrific to experience close up. People do die and get injured. Houses and barns burn down, Forest and brush land is burned – even if the risk of it happening to a certain person or place is small.

Addendum – I also see from the PHMSA site that about 10-12 % of the incidents were transmission lines and 15% of the fatalities – that means that my numbers over-estimate the risk by more than triple. Meanwhile over 80% of the incidents and over 70% of the fatalities are from distribution lines. This means that even though environmentalists call transmission lines “buried bombs” they are far less likely to explode and one is far less likely to die due to on exploding than for distribution lines. Thus, if they are truly interested in saving lives and lessening incidents they would be better off promoting replacement of old distribution lines than protesting against transmission lines. Graph below shows that transmissions pipeline explosions have not increased in the last 20 years (and through the advent and normalization of “fracked gas”) nor have fatalities.

References:

Causes of Natural Gas Pipeline Explosive Ruptures (Abstract) – by Richard M. Peekema, Ph. D., in American Society of Civil Engineers - Journal of Pipeline Systems Engineering and Practice, Vol. 4, Issue 1, Feb. 2013

Pipeline and Hazardous Materials Safety Administration 2018 (website/portal)

https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-20-year-trends

List of Pipeline Accidents in the United States in the 21^st Century, in Wikipedia

Environmental Regulations: Burdens, Overreach, Efficiency, Reform, and Certainty/Uncertainty: The Search for Effective Yet Sensible Regulation of Industry

Environmental Regulations:  Burdens, Overreach, Efficiency, Reform, and Certainty/Uncertainty: The Search for Effective Yet Sensible Regulation of Industry

Environmental Law is a subject that is quite debatable. Most often the challenge is to compare costs vs. benefits and to set boundaries between what constitutes acceptability and what constitutes environmental harm. With climate change and carbon emissions the challenge also very often includes the desirability of emissions mitigation or reduction.

There are different approaches to environmental regulation at all levels from federal to state to local. The approach of hardcore American liberals like Bernie Sanders is to super-regulate and punish polluters and carbon emitters. The approach of hardcore American conservatives has been to de-regulate. Obama’s approach was to regulate in some innovative ways such as the Clean Power Plan and in some specific ways such as the Waters of the U.S. Rule, and federal mandates for methane emissions reduction at oil & gas facilities. The right argued that he went too far, the far left that he did not go far enough. The Trump administration EPA under Scott Pruitt is attempting with significant success to undo most of the Obama era rules and to redefine the role of the EPA itself, charging that the culture had become too anti-industry. Now it is often seen as too pro-industry. It is a delicate balance for sure. Some on both sides favor regulation at state levels rather than federal. There are practical reasons for this including geography and regional natural resource endowment. Of course, if some states have more stringent regulations than others there will be outcries. Resource states grapple these days with rules about oil and gas severance taxes, forced pooling/co-tenancy of leases for drilling horizontal wells, state methane emissions mandates, spill prevention and containment, coal ash impoundment regulations, mountaintop removal mining overburden deposition regulations, etc. An example would be EQT, the largest American natural gas producer who drills wells in Pennsylvania and West Virginia. They are drilling long lateral wells to optimize economics. In Pennsylvania they can benefit from forced pooling of leases when a certain percentage (I believe it is 75%) of leasers in a unit agree to lease so that the other leaseholders at that point would be compelled to lease. That way a small holdout of one or two landowners can’t block development. Before the state of West Virginia approved such a practice this year – which they refer to as ‘co-tenancy’ – they would be able to block. For that reason, EQT favored developing Pennsylvania wells instead of West Virginia wells.

Of course, the ideal situation is to have regulators as a non-biased independent third party. However, in reality that is difficult to achieve. Regulators, industry people, and academics meet at conferences, talks, and society meetings and sometimes become friends. These meetings are educational, useful, even essential for all parties. Regulatory issues may be discussed. However, this is not to say that they are making deals simply by being friendly. Anti-industry people could also attend such meetings but they are less likely to be friended if they have strong positions against a majority of attendees. Charges of industry people becoming cozy with regulators or even the ubiquitous charges of “revolving door” policies where former regulators become industry people or lobbyists or vice versa may well be true but if you think about it they usually have the best qualifications. So, the potential for pro-industry bias is stronger than for anti-industry bias. There has to be some collaboration between regulators and industries and much of that is scientific and knowledge-based. While people from environmental organizations sometimes attend conferences, they tend to be less tuned into the science and engineering of the various industries. While there are some anti-industry activist scientists, typically academics, most have been controversial and less knowledgeable of industry and the changes within industry. It would be imprudent and potentially disastrous to have regulators making rules who do not have a solid understanding of the industries they regulate.

Regulatory burdens are real. If complying with new regulations makes a marginally profitable project unprofitable then that project would either have to be scrapped or more likely continued to be run at a loss. Since industries like oil and gas are subject to the volatile whims of commodities prices they have experience running projects at a loss while assuming future profit from recovering commodities prices. One example is a small refinery project operated by one of the majors where new methane leakage rues would require that project to be run unprofitably – at least for a time – although one would think that after initial investments in the “pollution controls” to capture methane the project would eventually return to marginally economic.

Scott Pruitt calls his approach “cooperative federalism” but it has been called a corrupt form of cooperative federalism, which environmental hawk Senator Sheldon Whitehouse calls “cooperative corporatism.” Cooperative federalism would involve the EPA collaborating with states to regulate but Pruitt has preferred to collaborate much more with industry and has been at odds with states that have strong regulations like California. As in much of American politics he (and many other politicians of both parties) is heavily funded by those industry interests. They have tended to simply ask industry how it would like to be regulated and try to get there. Trump’s Interior Secretary Ryan Zinke has also sought to make his department friendlier to extraction industries. This is also true of West Virginia governor Jim Justice, who is actually a very wealthy coal executive. They have sought to decrease “regulatory burden” on a rather unprecedented scale, although some of that is practical. Justice wants to make permits easier and less burdensome to obtain. That is rather practical in several cases where some permits, especially those involving multiple federal agency sign-offs, can take years, sometimes many years. This is true of hydro-electric projects as well as fossil fuel projects. The time factor can affect companies’ financing if there are long periods of “regulatory uncertainty.” Companies can lose large sums of money if regulation denies their projects going forward. For example, before the state of New York placed a moratorium on fracking (nearly a decade ago) there were several companies who had spent significant sums of money leasing and test drilling. They totally lost their investments as did landowners who stood to profit and local people who could have been hired for work. New York state’s environmental regulator also continues to deny pipeline permits, typically for issues that would temporarily affect water quality (sedimentation and erosion). New York is an example of anti-industry bias while Justice and Pruitt are examples of pro-industry bias. Rules often change with differing political administrations at all levels so regulatory uncertainty is often a function of change in political power, at least in recent times. Some companies, typically the oil majors, tend to favor some rules they see as financially do-able because they offer regulatory certainty which helps them plan better. They have tended to favor methane leakage rules and carbon taxes for these reasons. Since they plan projects on time scales of several years to a decade or more, having knowledge of the regulatory climate ahead can help them plan successfully. This is true of most companies where regs can make or break project economics.

Pruitt has also often touted ‘regulatory certainty’ as a reason for changing rules but so too did his predecessor Gina McCarthy and probably others before. Others claim his policy of undoing every Obama rule is creating the opposite, regulatory uncertainty, since any new administration, especially a Democratic one is likely to change things again. Logic would dictate that in order to create certainty there would have to be some middle ground found between the views from the left and from the right. Some level of compromise would be required.

Environmental protection has long been recognized as a public good. The usual issue is quantifying a boundary between acceptable and unacceptable environmental harm and impact. Some form of cost-benefit analysis is required to estimate where the baseline should be. Often, the individual companies in the industries participate in gathering the information that is used to set regulations. That aspect of what has been called ‘self-regulation’ is rather non-negotiable since the companies are usually by far the most qualified to do it. Other aspects of self-regulation such as frequency of reporting, monitoring of carbon emissions accounting is now strongly suggested by many corporate boards. Some are suggesting carbon contingency plans as well. This is happening with energy companies as pipeline builder/operator Kinder Morgan shareholders just approved non-binding measures to require just this. Kinder Morgan’s first response is that they will study and consider.

New facilities are also regulated by state requirements as shown by the control the state of New York has wielded regarding fracking and pipelines. Another example is the repeated denial of coal export terminal proposals on the West Coast to export Western coal. It is another case of being landlocked. In some cases involving international infrastructure projects the Feds may overrule as in the Keystone Pipeline which is set to deliver tar sands oil from Canada to the Gulf Coast. But most infrastructure projects are ceded to states to rule on them where applicable. At least they have veto power. Although the US EPA is often credited as being more stringent in requirements than states that is not always the case. In the case of the coal export terminals several interior coal states are going to federal court to say that the state of Washington’s denials were too ‘broad’ and that their access to international markets is being hindered on policy grounds. With global issues like climate change it is harder to justify coal but who gets to make those decisions and where and when are all up for debate. Though Washington state regulators did cite carbon emissions as one reason for the denial there were perhaps other reasons that were more significant such as an increase in local diesel fumes from the additional 16 coal trains per day expected to arrive at the terminal and impacts to the Columbia River. A similar situation is occurring in Oakland, California where plans to build a coal export terminal at the Oakland Army Base has been battled out in the courts and a federal judge has recently struck down bans on the terminal and associated coal trains that would bring the coal. Environmental justice advocates say the trains would bring coal and its fine particulate matter, presumably coal dust as well as diesel fumes through poor and minority neighborhoods of West Oakland where the export facility would be built. Pruitt is also in the process of ceding the management of coal ash slurry waste to states. In a different direction the EPA is being sued by 17 states for relaxing the national fuel standards set by the Obama administration. In that case there is consensus that a national standard helps auto-makers so ceding to the states is not recommended but California especially does not want to relax its standards and negotiations are underway. If the automakers end up like the utility companies they may continue to plan for stricter fuel standards regardless (assuming future administrations will go for stricter ones) much as the utility companies continue to plan for decarbonization.

Another issue with regulator and industry contact is claims of conflicts of interest. Of course, that is bound to come up and be invoked by those who seek to further regulate but in most cases it is simply not a big problem. Since regulators and industry have to co-ordinate and work together it is not unusual for potential conflict of interest situations to arise but that certainly does not mean cooperation equates to conflict of interest. While environmental protection is obviously a public good so too is fairness toward industry through sensible regulations. Claims of ethics violations often involve (at least nowadays with the Trump administration’s friendliness toward industry and deregulation agenda) former lobbyists and anti-regulation advocates being picked to run and staff regulatory agencies. While this may seem a slap in the face to those who see regulators as “opposed” to industry it need not be the case. In the Trump administration case it can certainly be argued that they are too friendly to industry and too eager to deregulate. Qualifications are another issue. Political appointees, including cabinet-level officials like Pruitt, can be seen as unqualified but of course, they have qualified staffs that they can rely on. Too many appointees can be seen as fostering too much of an agenda-driven focus.

Unfortunately, it is also true that sometimes states, industry, and industry advocacy groups will impede regulations for less noble reasons. An example there is perhaps the slowness which states, particularly Oklahoma and Texas, acknowledged that wastewater injection and in some cases pressure pumping water in the hydraulic fracturing process were inducing seismicity, causing small earthquakes. At first, the industry and groups simply denied that these were the cause – even though water injection has long been known to cause faults to slip. With more science and monitoring it became quite clear that this was the cause. Injection well operators were sometimes also at fault by not properly regulating injection pressures. In response, affected states have developed much better seismicity monitoring systems and regulation of injection pressures, water volumes, and in some cases injection zones. Incidentally, in some states the EPA manages wastewater injections while in other states they cede this authority to the states if they see the state policies as adequate.

Apparently, Pruitt’s EPA reorganization involves taking significant resources away from enforcement of environmental rules, presumably fines and other punitive actions. While some say this is effectively a license to pollute, others note that state regulatory agencies are also in play as well as giving the industries opportunities to self-regulate responsibly. Recently, the Ohio EPA as well as the Pennsylvania DEP have issue large fines against Energy Transfer Partners for significant violations involving the Rover Pipeline and Sunoco Logistics Mariner Pipeline respectively. Remedial action was coordinated with FERC which regulates interstate natural gas pipelines. So, despite federal EPA restructuring the state regulators are still regulating and enforcing quite effectively. The simple fact that the Western states can ban coal export terminals (although currently being challenged at Fed level) or that New York and a few other states can ban fracking and block pipelines (currently unchallenged at Fed level but pipeline blocks being considered for challenge) shows that state control in environmental matters is pretty strong, currently.

My own view is that environmental monitoring is important and that samples should be collected and analyzed – of air and water, and soil where applicable – at regular intervals and at places where contamination is more likely. This should be done not as a way to police industry as environmental activist citizen science advocates like to do, but as a general way to monitor the environment in a non-biased way. If monitoring finds contamination issues, then further studies can happen. Some regional organizations manage sampling and analysis systems. One is ORSANCO, the Ohio River Sanitation Commission. The Ohio River is considered the most polluted inland water way in the U.S. I grew up along this river spending much time near it. I saw a few large fish kills. Although such fish kills may occur from algae blooms they may also occur from spills related to oil and gas or coal mining activity. Mercury levels are often high due to coal-burning power plants and mercury advisories regarding the safety of eating fish caught from the river are often in effect. Recently, ORSANCO has been considering ceding its sampling and analysis authority to the states, the various DEPs, and the federal EPA. I tend to agree with the Ohio Valley Environmental Coalition that this may not be in the best interest of the public, but I don’t know all the details. The 2014 MCHM spill on the Elk River in Charleston (which flows into the Ohio River nearby) and the developing petrochemical hub along the Ohio River and its tributaries does suggest that an adequate monitoring system for spills should be in effect.

Environmental issues should be debated by the experts as well as the interested parties: states, feds, industries, experts from industry and academia, the more rational environmental groups, and local citizens potentially affected. It should be a collaborative problem-solving approach rather than political maneuvering. The co-opting of the public comment hearings process by radical environmental activists showing up at hearings not to voice specific concerns and help steer the process but to protest the various projects on general principles (particularly pipelines these days) only serves to erode the processes put in place where citizens can voice specific concerns relevant to the project.

References:

6 States Join Battle Over the Largest Proposed Coal Export Terminal in the U.S. – by Natasha Geiling, in Think Progress, May 14, 2018

Records Reveal Interior Official Met With Former Employer, a Koch-Funded Group Suing the Department – by Mark Hand, in Think Progress, May 14, 2018

Can Oakland Still Stop the Coal Trains? – by Nathanael Johnson, in Grist, May 17, 2018

Ohio River Pollution Control Standards Are in Jeopardy: Comment by February 24 – by Ohio Valley Environmental Coalition, Feb, 20, 2018

Gov. Justice Order to Expedite Permit Process Could Benefit Business, Oil Gas Industries – by Rusty Marks, in WV News, April 23, 2018

Scott Pruitt’s Guiding Philosophy is ‘Cooperative Corporatism,’ Per Senator – by Mark Hand, in Think Progress, April 10, 2018

Nothing Certain in Search for ‘Regulatory Certainty’ at EPA – by Nathan Rott, in NPR, May 22, 2018