The Current Local Controversy Over Waste Water Injection Wells in Southeastern Ohio and the Unlikelihood of Further Induced Seismicity in the State

The Current Local Controversy Over Waste Water Injection Wells in Southeastern Ohio and the Unlikelihood of Further Induced Seismicity in the State   This is an issue of local concern to me as I live near a town that has voted unanimously to ban fracking and some of whose constituents are advocating tirelessly to ban waste water injection wells in the county. As a geologist I have some knowledge of these issues. I have stayed out of these local debates, preferring to leave them to the official spokespeople of the industry such as the ODNR, the Ohio Oil and Gas Association (OOGA), Energy-In-Depth (EID), and others. Having gotten a letter from my local water company about the dangers of injection wells I was aghast at the misunderstandings. Apparently, this group ACFAN (Athens County Fracking Action Network) is advising them quite erroneously about why there are waste water disposal wells in Ohio rather than other states (ie. Pennsylvania). They are advising that this is due to Ohio having less stringent requirements for permitting such wells. This is simply untrue. There are two basic reasons that Ohio is far preferable than PA: 1) Many of the reservoir rocks at depth in Ohio are significantly underpressured relative to pressure gradient compared to the rocks at depth in PA. This allows them to accept more water. Pressure gradient is also higher in PA, ie. rocks at 4000 ft depth in southeastern Ohio might have a pore fluid pressure of less than 800 psi while rocks at the same depth in PA might have a pore fluid pressure of 3000 psi. This is due to greater compaction due to burial at greater burial depths in the basin-center regions of PA and WV relative to the basin-marginal areas of Ohio. Thus, reservoir rocks in PA are typically at higher pressure at depth (higher pressure gradient or psi/ft below surface) and so it is generally easier to inject fluids into the Ohio rocks. Pennsylvania also has more overpressured reservoirs, where the reservoir pressure is actually higher than the pressure gradient. This means that Ohio rocks tend to accept more fluids than PA rocks. 2) Ohio has more brine-bearing reservoirs at depth (deep saline aquifers) than PA. Some are significantly naturally fractured which helps them accept more water. A few a naturally underpressured and some are pressure-depleted. Under-pressured or pressure depleted brine-bearing reservoirs or under-pressured reservoirs that are significantly naturally fractured are ideal for water disposal because they will accept water easily at lower injection pressures - with rising pressure being temporary, dropping as the water moves away from the well bore via injection pressures. ODNR was given primacy by the Federal EPA to regulate waste water injection wells because its rules equal or exceed those of the EPA regarding these class II injection wells. This is the case for several states. The state (Ohio) does tend to approve permits significantly faster (than EPA-regulated PA) due to pro-business efficiency and more staff devoted to the task.  There may be some potential for waste water injection in Pennsylvania in pressure depleted Oriskany Sandstone gas fields. These wells have lower pressure, being depleted of their reservoir fluids. Pressure depleted reservoirs are thought to have very good long term capacity but injectivity is dependent on permeability of the rock. At least one proposed and initially approved injection well permit was later rejected by the EPA (who controls underground injection in PA) likely due to public concerns. Perhaps the most pertinent issue there is that both the well operator and the EPA failed to identify many of the fresh water wells within a quarter mile, which is required. It is uncertain why this is the case and how well documented water wells are in the state. Certainly it was a serious oversight. The wells being permitted there should be approved and likely will be at some point as there should be no reason to be concerned about fresh water aquifers. There is also some possibility for depleted Clinton/Medina wells in northwest PA to be converted to injection wells.  Early in the development of Pennsylvania Marcellus wells the frac flowback and produced waters were treated in public waste water treatment plants. Most of these plants were not equipped to remove some of the contaminants. Before the rule was in effect the PADEP asked producers to avoid certain of the most ill-equipped plants and they complied quite readily. This practice was halted in 2011 and it probably should have not been permitted in the first place. Water with high concentrations of total dissolved solids (TDS), bromides, barium, and some with unacceptable levels of radioactivity due to radium isotopes has been found near discharge areas.  However, these are no longer problems and surface water quality in southwest PA has improved. Radioactivity in Shales and Brines The source of radioactivity in flowback and produced Marcellus waters was originally thought to be from dissolved radioactive shale fines from the drilling and fracking processes but studies have indicated that the radioactivity is present in existing formation brines. Some wells likely also tap into Oriskany brines which likely have similar compositions. The Oriskany Sandstone is one of the injection zones in Southeastern Ohio and Athens County and adjacent areas where fluids are contained in updip stratigraphic pinchouts. Since radioactivity is already present in these formation brines then injecting more radioactive brines should not be problematic. See references. Recently, an industry colleague has confirmed to me that Oriskany brine waters from PA are typically "hot," or radioactive. The high capacity and deeper Clinton/Medina sandstones and Newburg/Lockport dolomite as well as the shallower fractured Devonian shales are also injection zones in this area. The Oriskany, Onondaga, and Devonian shales are considered to have less capacity and be low volume injection zones while the Silurian Newburg/Lockport and Clinton/Medina are high volume injection zones. I am not aware of any radioactivity in the Silurian brines but since they are not adjacent to an organic-rich black shale I would suspect much lower naturally occurring radioactivity.     Injection Well Construction Another serious error I have noted with the endless coverage of anti-injection well groups is that they appear to be misinformed about how wells are constructed to protect fresh water aquifers. There are typically three strings of high pressure rated steel casing cemented in place. Cement bond surveys and other detection surveys are run to make sure the cement is fully functional as a fluid barrier. Sometimes it falls out a bit at the bottom or where it washes out so that it does not come to the top but in those cases it is typically back filled then re-checked with surveys and casing pressures are always monitored. Lastly, a steel production casing is run inside the other casing strings to the injection depth. This does not need to be cemented in place to the total depth as the other strings protect fresh water zones. A packer is inserted around the injection casing to prevent any fluid from coming up around the injection casing and the pressure is monitored. In addition there are typically thousands of feet of rock between the injection zone and fresh water aquifers including aquicludes, which are impermeable layers of very fine-grained rocks like non-organic shale. Typically, there is one just above the reservoir into which the water is injected which acts as a seal for the reservoir fluids. There are many many studies that show that fluid boundaries such as these are rarely compromised and even if one was there would still be thousands of feet of rock including more impermeable layers to seal fluids in, especially at the low rock pressures in southeastern Ohio. The ODNR and other regulators assign maximum allowable surface pressures. The EPA has recently praised the ODNR underground injection control (UIC) program as more than adequate and responsive to problems. http://www.ohio.com/blogs/drilling/ohio-utica-shale-1.291290/u-s-epa-hails-ohio-s-injection-well-program-for-drilling-wastewater-1.625017  Underground Reservoir Fluids and Characteristics Incidentally, also in those rocks underground there are fluids like natural gas, condensate, crude oil, in some cases hydrogen sulfide, and other sulfur compounds, sometimes CO2, nitrogen, possibly even helium in some places. There are also organic Devonian shales rich in uranium, thorium, radium, etc., and so radioactive. Some of these naturally-occurring gases and substances are inert but most have some level of toxicity- most are more poisonous than the dilute hydro-fracking waste water that is injected. It should also be remembered that groundwater and formation fluids move laterally very slowly. While groundwater movement is dependent on recharge and discharge dynamics and can move quickly, fluids at depth are much more strongly confined and flow is limited and typically on the scale of inches per year. It may move further and faster at higher injection pressures. The Battelle/RPSEA study noted that injection pressures drive fluid migration. They note that fluid injected into the injection wells is generally confined to an area around 3000 ft from the wellbore - and this is presumably in wells that have been injected into for 20 years or more in some cases. This migration can be detected by nearby wells drilled into the same formation. Fluid migration is certainly an issue in Oklahoma and Kansas allowing fluids to access basement faults that induce seismicity. This slow water movement is in great contrast to surface water which flows according to gradients provided by topography and gravity. Water injected at high volumes and pressures into deep saline aquifers does diffuse more quickly (possibly in the range of a half-mile per week as the Youngstown study indicates) but is confined to porous and permeable stratigraphic intervals according to the mechanisms of deep basinal fluid migration and the porosity and permeablility of the reservoir. It also has been shown that so-called "make-up water," the frac water that goes into a well is different than what comes out. The water that comes out has more salts, heavy metals, and organics (benzene, etc.) than the make-up water. Since drilling mud is circulated out and reused, it is unlikely that any significant amounts of these components come from drilling mud. These higher concentrations of chemicals of concern are inherent in the naturally-occurring formation water. What this means is that the focus on fracking chemicals as dangerous relative to naturally occurring brine water is unwarranted.  Brine water and Spills   Typical Ohio brine waters from conventional wells are variable in chloride components but some are very salty (much saltier than seawater - up to 10 times) and the state reports that approximately 2% of oilfield brine is being poured on roads to melt snow in winter. This can cause accumulations of salt in groundwater as has apparently been documented. These brines are far from drinkable and are dangerous to plant life. I would say they would probably be more dangerous in drinking water than hydro-fracking make-up water mainly because it is far less dilute in general and more saline. Use of road salt has declined somewhat over the years in favor of other substances like calcium chloride, magnesium chloride, and organic agricultural by-products but rock salt (NaCl) and oilfield brine are still used considerably. It should be noted that surface spills would be magnitudes more likely to get into groundwater than any deep fluid injection. There is usually access from surface to aquifer and rarely if ever access from deep zones to aquifer. Deliberate spills, or dumping of brine waters has occurred and this is, of course, a felony criminal offence, as it should be. There was one well-known case in Ohio where frac waste water was dumped into storm drains leading directly into a river. In North Dakota there have been several cases of deceptive injection well owners, one who moved a packer up the hole in order to be able to inject more fluid. This indicates that a compliance culture needs to be encouraged, developed, and enforced among oil & gas producer and injection well operators.  Since waste water has been transported much more via pipeline rather than being trucked there have been far less spills, however, the spills (pipeline ruptures) that have occurred have been larger. This shows a need to be able to both anticipate spills before they occur and to detect them faster when they do occur. The trend is that legal liability for leak detection is being transferred to the "operators" of the water pipelines rather than the companies who utilize them (which may be multiple companies).  Recent spills in Ohio and West Virginia have spurred lawmakers to propose new regulations regarding underground tanks and vaults that temporarily store wastewater and to require dyes so that spills can be found sooner. These have a fair liklihood to be enacted as these spills were preventable. One underground storage facility leaked, perhaps for a long time into a neighbor's pond and killed a significant amount of wildlife. Companies operating these wells need to ensure maximum protection against surface and shallow subsurface spills.  Shallower Injection Via Enhanced Oil Recovery Projects In southeastern Ohio there is some shallow oil in a formation known as the 2nd Berea. For many decades now there are places where this zone - at about 1100 to 1800 ft (it shallows westward) - has been water flooded which means that water is injected in to push oil out. Water comes out with the oil then is filtered and treated then re-injected. There are about 120,000 such projects in the U.S. There are no known instances of freshwater contamination through water flooding here of which I am aware. Certainly the most dangerous potential situation involving the local southeastern Ohio injection wells would be via a major spill, say if a holding tank or a truck leaked its contents. If not mitigated quickly it is possible such a spill could eventually rich a fresh water aquifer, especially a very shallow one. However, the injection well sites are properly diked with multiple containment that exceeds the contents of their holding tanks, so the chances of a spill getting into groundwater are very small.   Local Water Issues The local water wells here in Meigs County tend to be deep - soft water which probably contains small amounts of chlorides and maybe sometimes a bit of methane as there is some shallow gas. Iron bacteria is fairly common and is typically mitigated with chlorine bleach. The local water company wants to be able to test for oil and gas "chemicals" that would be introduced into the aquifer thousands of feet above via injection well fluids but complains that they don't know what to test for since information on the chemicals used is unavailable. Of course there are many known chemicals and nearly all can be accessed through the Frac Focus database and through other means so that is not really a valid argument. Their overall concern is understandable due to the long term local contamination caused by the C8 (perfluorooctanoic acid) released directly into the surface environment by DuPont. However, there is a vast difference between releasing something directly into the surface environment and releasing it into the deep subsurface.         The bottom line - the reason I write this post - is to counter the misunderstandings and hopefully to allay any fears people may have about the safety of their water. The biggest danger to my local water supply would likely come from the Ohio River where oil and gas leakage, if any, would make up just a small part of the total industrial leaks, pesticide and fertilizer runoff, iron bacteria, sewage leaks and raw sewage discharges, grey water, landfills, underground storage tanks, acid mine drainage, falling particulate matter etc., that affect the local watersheds and groundwater. Attempting to convince people that this one highly regulated potential source, which is carefully injected thousands of feet below aquifers, is more dangerous than the others is not realistic. When we still had the C8 in our local water I tended to avoid it but now that it is at virtually undetectable levels I don't. Two things I learned when studying water are 1) that it is most often a local issue, and 2) water can be cleaned (though the cost can get high to clean it at high levels). Of course, nobody wants contaminated water. There are tens of thousands of oil and gas wells in Ohio where the pipes come up through aquifers but there have been only a handful of cases of water contamination and in each case the cause was determined and remedied as needed: human error, spills, improper design or procedure, etc. Billions of barrels of oil and brine have come up through these pipes without any noticeable problems. The current oil and gas industry is much more conscious and less tolerant of improper procedure that could result in environmental problems than it has ever been in the past. It has to be. People who work in the industry want to produce their products safely and environmentally responsibly.  Manageable Risk While groups like ACFAN can show good organizational skills and documentation of spills and accidents, they fail to understand basic processes and so fail to convey an accurate picture of what is really happening or what is the actual level of risk. Someone could list thousands of cases of car accidents to point out the dangers of driving but we understand that it is an acceptable risk. Injecting brine and frac flow back water is also an acceptable risk. There are many other things the industry is doing to help: recycling as much water as possible, utilizing treated acid mine drainage for fracking to keep it out if the surface environment, researching new ways to treat and recycle waste water, and to dispose of effluents. Companies are also engaged in offsetting activities: restoring wilderness areas, wetlands, forests, and helping local communities, as well as providing jobs. Water Treatment Facilities Antero Resources and Veolia North America (the largest water treatment company in the world) just announced designing and building a state-of-the-art wastewater treatment complex initially able to process 60,000 barrels per day. Antero, along with many other companies, utilizes their own fresh water pipeline distribution system to move water to their wells to reduce trucking. Waste water treatment facilities can help companies recycle up to 100% of flow back and produced water. Other marketable byproducts can be produced such as salt and brine products for oilfield use. The treated water can be returned to the fresh water distribution system to be used on future wells. Such projects can potentially decrease the amount of waste water injection wells needed. There will likely be more of these projects in the future. http://investors.anteroresources.com/investors-relations/press-releases/press-release-details/2015/Antero-Announces-60000-Barrel-per-Day-Advanced-Wastewater-Treatment-Complex/default.aspx   There are other new technologies for water treatment and recycling such as 'crystallization and evaporation' that are seen as alternatives to underground injection. Such processes involve large surface impoundments so the risk for spills is not really reduced and the advantages over deep well injection may not be great. Fairmont Brine Processing recently announced such a project capable of processing 52,500 Bbls per day. By-products that can be sold include sodium chloride and calcium chloride. They expect their project to be operational in 2018.     Media, Activism, and Science It would be best if the ACFAN people would cease and desist going around “educating” other people about these wells as they themselves are most certainly not properly educated about them. They have been very influential in the local area and their loud voice has been extremely well represented in local and regional media. In light of their incorrect knowledge, they should be challenged: by the ODNR, by the companies operating waste water injection wells, by the local oil & gas industry and their reps and PR groups (OOGA and EID) and by the EPA. Creating hysteria and sending out notices to tens of thousands of people that their water might be poisoned can be seen as a very serious accusation, one that had better be backed up by correct knowledge. That is not the case here.   Calls for monitoring wells near the tank batteries of injection wells have been deemed unnecessary by the ODNR and knowing the process and the geology this is quite understandable.  The ODNR could maybe provide other cases where water wells were monitored near injection wells. One should also understand that finding traces of chemicals in water similar to those used in oil and gas does not pinpoint the source of those chemicals, as well construction materials and other local sources of the same chemicals and chemical by-products can and do occur. This has been a problem with a few other monitoring efforts with the results often being misrepresented by media. The ACFAN group has also complained repeatedly about the need to have public hearings before such wells are permitted but when ODNR had an informational format open-house they made a spectacle of it by loud protesting with signs and slogans. Many such hearings have been disrupted by anti-drilling groups which makes them uncomfortable to others. In any case ODNR is not required to have such hearings and has never had them in the past. These people have an agenda. A few years ago they put up a billboard with children and flowers and a smoking burning oil rig in the background. They are manipulative. Unfortunately, people are falling for their ability to portray themselves as knowledgeable experts which they are not, quite obviously to anyone who has some real knowledge. Groups like ACFAN have no interest in making extractive industry processes safer and more accountable. Their goal is to ban those processes and this is pretty clearly stated. Science to them only has value if it confirms their own biases and supports their agenda. There are other environmental groups who are more reasonable and willing to work with industry and regulatory bodies to influence policy and solve problems. They tend to be more influenced by science and thus should have more influence on public policy than groups less informed by science.  The argument that Ohio is a "dumping ground" for Pennsylvania fracking waste is not so valid if one considers that about 2-4 million gallons of injected frac fluid per well remain in the formation in each PA Marcellus well. Thus the complaint that up to 600,000 gallons of waste water per day injected in Athens County is extravagant is not valid as it would be equivalent to about 73 fracked wells per year. There are counties in PA that have drilled far more than 73 wells per year, although they are of course spread out over 73 or more sources of fluid rather than a handful in the county as in the injection wells. That number may be too small as it has been noted that 70% or more of the frac water injected into a production well does not return to the surface. That would be close to 120,000 barrels (5 million gallons) per well. In that scenario there would be only 42 wells worth of waste fluid injected annually in the county.   There are about 150,000 waste water injection wells in the U.S. Most of these are small-scale enhanced recovery operations but about 30,000 wells are brine and flowback waste water injection wells. There have been very few problems with these wells concerning contamination.  Ohio has 211 injection wells. West Virginia has 76. Kentucky has 30. Pennsylvania only has 7. Geology, reservoir capacity, pressure relative to gradient, and permeability are all factors in a rock's ability to accept water and accommodate injection pressure tolerances. The avg. injection well in Ohio injects 32,000 barrels per year (1.34 million gallons) at an avg. reservoir pressure of 543 psi. In Ohio the Newburg/Lockport and Clinton/Medina formations have the most available volume and high injectivity. They also have had the most waste water injected. Injection-Induced Seismicity A very small percentage of wells have been associated with seismic activity and this is concerning. These wells have been associated with known and suspected faulting as it is well-known that fluid injection can trigger small earthquakes. In Oklahoma the USGS has determined that water injection along with water removal (many wells in Oklahoma, both conventional and unconventional produce lots of water along with oil and gas) has contributed to the upsurge in earthquakes. Wells in Ohio that have triggered earthquakes have been shut down. New rules, better volume and pressure monitoring, and better seismicity monitoring have been put in place here and in other areas. The case in Youngstown, Ohio has been examined in detail and it has been noted that sources of the injection-induced seismicity can be located with a high degree of accuracy so the seismic monitoring networks are adequate. Holtkamp etal. note that the monitoring networks in place can "quickly and inexpensively diagnose cases of induced seismicity and identify responsible well sites and operational parameters before induced events reach potentially destructive magnitudes." The uniqueness of the Youngstown case is that the injection zone was a 700+ ft interval from the Cambrian Copper Ridge Dolomite "B" Zone through the basal (Mt. Simon) sandstone and 200 ft into Proterozoic Precambrian basement rock. The Proterozoic interval was where the seismic events and thus the fault slippage was located. Most injection wells in Northeast Ohio inject into Silurian Age Lockport Dolomite (Newburg). Study of the Youngstown events was able to determine that the seismic events were a function of pore fluid pressure diffusion leading to fault slip with the slip leading to further pore fluid pressure diffusion (a positive feedback mechanism) . They were also able to determine that increasing injection pressures and volumes led to further diffusion and slippage and increased the area of potential failure of the fault zone. They also determined the diffusion rates by noting times between injection pressure increases and seismic events that were pinpointed to within 50 ft of accuracy in any direction. Finally, they also determined that ceasing injections led to drastic decreases in seismic events. This data suggests that injection-induced seismicity can be determined quickly, pinpointed to specific wells, and the wells shut down, likely leading to no further problems. Even though there have been quite a few individual cases of induced seismicity the phenomenon overall is still very rare and the increased cases are likely the result of the increased volumes of waste water being injected due to high-volume hydraulic fracturing of horizontal shale wells. As reservoir pressure decreases when fluids come out of the ground it increases when fluids are injected. That is a big part of the situation in Oklahoma - as pore fluid pressure diffuses further from the injection source due to higher reservoir pressure causing the fluids to move towards lower pressure there is more likelihood of accessing faults. The Cambro-Ordovician Arbuckle formation (roughly equivalent to the Knox and Copper Ridge formations of Ohio) which sits directly on top of basement rock is the main injection reservoir there with known access to basement faults. Researchers there (including the recent Stanford study) have noticed increased reservoir pressures in some places in the Arbuckle which moves the fluid that eventually intersects a fault which can cause fault slippage. The model developed by geophysicist Mark Zoback and colleagues at Stanford explains the time delay between injection and the small earthquakes as the time it takes for the pore pressure to diffuse and eventually intersect the basement fault. Oklahoma now injects 20 times the waste water that they did in 1997. Over 90% of the water is produced water rather than frac flowback water, so much of it is from conventional rather than unconventional development. Some Cambrian injection reservoirs in Ohio, Oklahoma, and Kansas are likely in hydraulic communication with Precambrian basement faults. Their situation in Oklahoma and Kansas is more dire than Ohio because their main injection reservoir sits directly on basement rock while in Ohio there are several shallower Paleozoic reservoirs: Clinton, Lockport, Oriskany, Huron Shale, etc. that are preferred to the Cambrian reservoirs. These shallower reservoirs are very unlikely to contact any basement faults. The Stanford authors conclude that stopping injection in the Arbuckle and instead injected into the Mississippi Lime where much of the produced water comes from is the best overall solution as it can be used for enhanced oil recovery. They do note that the pressure is still spreading in the Arbuckle and further intersections with basement faults and thus earthquakes are possible even after injection stops. In Ohio this is not an issue because most of the injection has been in shallower reservoirs far from basement rock. Recent actions in Oklahoma to shut-down certain injection wells and reduce pressures and volumes in others have resulted in a decrease in earthquakes, as expected in the modeling. The bottom line is that if the now obvious steps are taken injection-induced seismicity is not likely to be problematic in the future. The science-based approach is working. While the hydraulic fracturing process itself does generate detectable microseismic events, larger events are quite rare, far rarer than injection-induced seismic events. However, they do and have occured in a few places such as the U.K, Western Canada, and few other places. In Western Canada they occur associated with fracking the Montney and Duvernay shales. Apparently, the largest induced-seismicity event on record in the world at 4.5 on the Richter scale occurred in British Columbia in this context. Seismicity monitoring requirements and regulations for states and provinces have been or are being developed in areas where earthquakes occur. There are companies that can do detailed and accurate seismicity monitoring. Earthquakes and ground movement are also occasionally associated with gas or oil production in unconsolidated sandstones that can compact when depressurized. This was the case with an oil field near Long Beach, California where sinking land from subsurface compaction was the problem. It also occurs in the Groningen gas field in the Netherlands, owned by Shell and Exxon. Small earthquakes have been occurring for about 25 years near Groningen, often damaging nearby houses. The land surface there is soft clay which is more amenable to transmitting ground movement through the frequent small quakes. Whether earthquakes are "felt" is dependent on land surface - unconsolidated soils and rocks tend to transmit energy better which results in more perceived movement. Potential for Lightning-Induced Fires and Explosions at Injection Well Facilities Apparently, fires and explosions due to lightning have occurred at injection well facilities. The explosion/fire risk is due to volatile gases released during separation of oil and water. This is more common in areas that produce light volatile oil, such as North Dakota, Colorado, and Texas. Since 2013, North Dakota has had 3 events, Texas 4, and Colorado 2. Fiberglass tanks, although much longer lived than steel tanks since they resist corrosion due to the brine, are more prone to ignition by lightning. Risk can be minimized by reverting back to steel tanks, grounding, and ionizing. There is some expense to these processes and some have called for regulations requiring preventative action though none are yet in place. This has not happened in the eastern areas, perhaps due to the overall less volatile brine. It may well be related to the areas with light volatile oil, such as the Bakken, where train derailments have caused massive and catastrophic explosions.         Future Waste Water Injection Projections are that the need for brine and flowback waste water injection wells is expected to grow modestly over the coming years due to the increasing pre-eminence of high-volume hydraulic fracturing of horizontal wells, predominantly in shale gas and oil wells. This is not expected to overwhelm any capacity of available reservoirs for fluid disposal. This is despite the fact that currently in the Marcellus region about 87% of frack flowback water is recycled while about 13% is injected into disposal wells. It is thought to have improved to over 90% in 2014. The recycling rate in the Marcellus areas is the highest in the nation. With more water treatment facilities the amount of water recycled is likely to increase further. Several companies currently recycle 100% of their frac water and the trend is for more to do the same. This may cut the modest growth in injection predicted.One current prediction is for 5-10 new wells per year with some capable of receiving over 1 million barrels per year (avg. 3000-5000 barrels per day). Injection well owner-operators project that an injection well needs to be capable of injecting 1000 barrels per day in order to be economic. The best injection reservoirs in Ohio are probably the Newburgh/Lockport and the Clinton/Medina. While the Cambrian reservoirs may be able to take on large amounts of water the risk for seismic activity should be considered too risky and they should probably be avoided. That could even become an issue if Cambrian deep saline formations like the Mount Simon Sandstone become CO2 sequestration reservoirs, although the buoyant properties of CO2 may alter that possibility somewhat. Latest News Update - Sept 2015 At the end of August a coalition of national, regional, and local environmentalist groups threatened to sue the EPA if it did not review and revise rules on oil & wastes as it apparently stated it would back in 1988. The issues of concern include injection wells, open air pits for temporary storage of frac flowback water, disposal of drill cuttings and solids in landfills that are not adequately lined, and spreading of frac waste brine on roads to melt snow. Induced seismicity is one of the biggest concerns with injection wells and I think with proper siting, monitoring, and injection zones that will not be a further problem in Ohio. If further events do occur then they would have to look at reducing injection pressures and volumes. The problem with drill cuttings and solid wastes includes heavy metals, some organics, and especially radioactivity although most studies suggests the radioactivity is low level and should not be problematic. As mentioned above there are plenty of alternatives to spreading oil and gas field brine on roads. My guess is that EPA may address some of these issues with small changes. Regarding injection wells they could possibly move to limit per well pressures and volumes as a safeguard against induced-seismicity. However, in light of recent understanding of the issues they may not. States are probably adequate to reduce risks. It was recently announced in Athens County that baseline water testing will take place within a two-mile radius of injection wells paid for by Ohio University (as part of an on-going study that already did some baseline testing) and Athens County as the commissioners reported. It would be illogical to assume they will find anything at all related to oil and gas waste as I suspect they expect to find, but since it is baseline testing it assumes that further testing will occur in the future presumably at further cost to the university and the county - update Dec. 2015 - the first battery of tests showed zero contamination. A trace of naturally-occurring methane was all that was detected. Second battery of tests scheduled for March 2016.       The ODNR has a video on their website that shows the whole injection well construction and functioning process. http://oilandgas.ohiodnr.gov/industry/underground-injection-   References: Geochemical Evaluation of Flowback Brine from Marcellus Gas Wells in Pennsylvania, USA - by Lara O. Haluszczak, Arthur W. Rose, and Lee R. Kump, in Applied Geochemistry  2012 Shale Energy Produced Fluids Management and UIC Disposal Trends - by Dave Yoxtheimer, PG, Hydrologist, Penn State Marcellus Center for Outreach and Research, presentation for GWPC Annual UIC Conference, Austin, TX February 10, 2015. Regional Detection and Monitoring of Injection-Induced Seismicity: Application to the 2010-2012 Youngstown, Ohio Seismic Sequence - by S.G. Holtkamp, M.R. Brudzinski, and B.S. Curie in AAPG Bulletin Vol. 99, No. 9 (Sept. 2015) pp.1671-1688 Oklahoma Earthquakes Linked to Oil and Gas Wastewater Disposal Wells, say Stanford Researchers in Stanford Report - June 18, 2015 (news.stanford.edu) Water and Shale Gas - by Paul Ziemkiewicz (West Virginia University) - presented at 2nd Environmental Considerations in Energy Production Conference, Sept. 2015 North Dakota Saltwater Disposal Enforcement Highlights Key Legal Risks - posted in Oil Pro - Sept. 30, 2015 Potential Injection-Induced Seismicity Associated With Oil & Gas Development: A Primer on Technical and Regulatory Considerations Informing Risk Management and Mitigation - Report by States First, Ground Water Protection Council, and Interstate Oil and Gas Compact Commission 2015   Injection Wells: An Introduction to Their Use, Operation, and Regulation - Groundwater Protection Council - Sept. 2013  Subsurface Brine Disposal Framework in the Northern Appalachian Basin: Injection Horizons, Geology, and Operational Data - by Battelle, National Energy Technology Lab (NETL), Research Partnership to Secure Energy for America (RPSEA), and WV, OH, PA, KY Geological Surveys - 2015 Development of Subsurface Brine Disposal Framework in the Northern Appalachian Basin - by Joel R. Sminchak and Dr. Neeraj Gupta, Batelle - presented at RPSEA Onshore Technology Workshop, Oct 27, 2015 Challenges and Strategies for Monitoring Induced Seismicity - presented by Dario Baturan of Nanometrics at Ohio Geological Society meeting, October 29, 2015  Shell and Exxon's 5 billion Euro problem: gas drilling that sets off earthquakes and wrecks homes, news story - by Lucas Amin, in The Guardian, Oct. 10, 2015 Energy Pipeline: Exposure to Lightning Strikes at Injection Well Facilities - by Gary Beers in Energy Pipeline (Covering the Energy Industry in Colorado), August 9, 2015  Incorporating Induced Seismicity in the 2014 United States National Seismic Hazard Model -Results of 2014 Workshop and Sensitivity Studies - by Mark D. Peterson, Charles S. Mueller, Morgan S. Moschetti, Susan M. Hoover, Justin L. Rubenstein, Andrea L. Llenos, Andrew J. Michael, Williuam J. Ellsworth, Arthur F. McGarr, Austin A. Holland, and John G. Anderson, USGS Open-File Report 2015-1070, 2015 Injection Wells and Earthquakes: Quantifying the Risk - A Report by Energy In Depth, Nov. 2015 Evaporation and Crystallization as an Alternative to Deep Well Injection - by Brian Kalt, posted in LinkedIn Pulse, Dec 10, 2015 Abstract 08: Class II Injection in the Wenlockian-Ludlowian Lockport Dolomite, Northeastern Ohio - by Michael P. Solis, in Eastern Unconventional Oil & Gas Symposium, Lexington, Kentucky, Nov. 5-7, 2014 Vienna Oil Spill Leaves Slew of Dead Animals - by Amanda Smith, in WKBN News, Youngstown, April 3, 2015 Ohio Representatives Want More Rules for Injection Wells - by Gerry Ricciutti, in WKBN News, Youngstown, Jan. 12, 2016

Utica/Point Pleasant Resource Evaluation And Appalachian Upstream and Midstream Development Updates (Aug 2015)

Utica/Point Pleasant Resource Evaluation and Appalachian Upstream and Midstream Development Updates (August 2015)

Resource Estimates

Recent hydrocarbons-in-place estimates for the Utica, Point Pleasant, and Logana Member of Trenton/Lexington Limestone range up to a whopping 1.7+ QCFeq! (QCFeq = Quadrillion Cubic Feet.) Original USGS technically recoverable resource was 38 TCF, 940 MM Bbls of oil, and 208 MM Bbls of natural gas liquids. In Dec. 2014, Irene Haas of Wunderlich Securities roughly estimated the resource at a minimum of about 90 TCF equivalent based on investor presentation statements of the main large players. The newest numbers, revised upwards by recent high volume wells, are by the WVGES and assume recoverability for three main zones throughout the basin and make some assumptions, but seem to be based on fairly standard reserve estimation principals. Their new technically recoverable resource estimate is about 782 TCF and 800 MMBbls of Oil. These numbers suggest that the Utica/Point Pleasant/Logana resource is even larger than the Marcellus. Last year the technically recoverable resource was estimated (but not announced) by the same consortium at 188.6 TCF and 840 MM Bbls of oil. In any case, the total unconventional shale resources of the Appalachian Basin, including the Utica-Point Pleasant-Logana resource, the Marcellus, Burkett, and other Upper Devonian resources seem to be somewhere around 1.5 QCF. Actual production from these new unconventional shales, mainly over the last five or six years, is now approaching the equivalence of all the previous hydrocarbons produced from the Appalachian Basin. Goldman-Sachs just reported a prediction that shale production will double by 2025. That implies vastly improved takeaway capacity and increased demand for gas and oil. Many companies are poised for better market conditions and can likely ramp up quickly to increase supply if it would be economic. Now that this resource has been defined and major infrastructure upgrades are commencing, the focus should be on effective and safe operation, efficiency, multi-year planning, and public acceptance. 

   

Development Constraints

The initial identification and characterization of this resource is now fairly well done, with perhaps some geological and technological refinements to come. The development of the resource is mostly constrained by the markets. Pipelines, LNG, gas power plants, and diesel-to-gas transportation are set to slowly open the tap to new markets over the next 5 years. Curtailment is the current case with Appalachian dry gas which sells for considerably lower than NYMEX. There are new markets appearing as well for natural gas liquids such as ethane, propane, and butane. Direct gas marketing and hedging offered some advantages to companies well positioned to provide firm deliveries but those hedges are now expiring. Pipeline projects are in various stages of development but should begin providing some glut relief soon. LNG exports are slated to begin in a few months. 1 QCF at Appalachian prices around $1.50 per MCF makes that resource worth 1.5 trillion dollars at current prices. At current NYMEX price it would be worth closer to 3 trillion. Through time the price and the value will probably rise considerably as production is consumed and wells decline. For comparison the global GDP for 2015 is estimated at 74.5 trillion dollars. There is also considerable resource development constraint by the public, with some zoning out of oil & gas activity, avoidance of sensitive areas, and unlease-able property. These public constraints can significantly reduce recoverability. Perhaps the term-phrase “accessibly recoverable” should be used, or at least the unrecoverable portion will need to be subtracted from the technically recoverable delineation.

Market Potential  

The new reserves numbers for the Utica sequence along with the entire massive Appalachian gas source is attractive to several markets. A stable source of cheap CNG for natural gas vehicles (NGVs), for transportation, for ships, trains, and significant heavy equipment applications, is one market. This market is currently small but is expected to rise, especially with possible state and/or federal incentives likely. Several LNG export terminals are in various stages of completion with first exports expected to go out at the end of the year. Plans are being made to ship gas via Chinese LNG tankers to Germany from Canada with Marcellus and Utica gas through New England after a major pipeline (Constitution) is built. This pipeline would also make gas much more affordable for areas of New England, with potential savings of millions of dollars for customers. Other Marcellus and Utica gas will go through the Buffalo area of National Fuel Gas (Seneca Resources) to eastern Canada. The Constitution Pipeline is expected to relieve some of the gas glut in Northeast. It is expected to be in operation in in the 2^nd half of 2016. It will also offer natural gas service to homes in areas where it has not been available. Marcellus gas has allowed many large buildings and residences in New York City to switch from home heating oil to natural gas, giving cheaper energy to customers and significantly improving air quality in the city. The Atlantic Coast Pipeline will make Marcellus and Utica gas available for gas power plants in the southeast so that those areas will be able to meet more stringent emissions requirements, become more efficient, and save their customer base hundreds of millions of dollars. There are several other major pipelines reaching out to other markets. Announcements to build ethane cracker plants, gas processing facilities, and NGL pipelines will allow NGLs to go to market, be processed into products, and relieve problems with excess ethane in gas pipelines. These gases and products are used as feedstock for the chemical, plastics, and fertilizer industries. Some companies are in the process or have pending deals to ship NGLs to Europe and other areas. On August 1^st (2015) the Rockies Express pipeline (REX) commenced continued reverse flow of gas and should provide cheaper gas to the Chicago market. Several other major pipeline and export deals are in the works. De-ethanization and NGL fractionation capacities are set to increase beginning later this year and into 1Q 2016. Overall management of this vast resource is taking shape. This can probably be done effectively and efficiently since core areas have been defined at least initially. The fact that the technically recoverable reserves of these reservoirs (Marcellus, Utica, Burkett) are now loosely defined allows for better and more efficient planning of infrastructure. The size of the resource lends support for long-term projects. The nature of unconventional resources as a continuous resource is well suited to efficient infrastructure planning and operation over long time periods.

Natural Gas and NGL Demand 

Most scenarios show increasing demand from now (2^nd half 2015) into the foreseeable future. Most demand sources are projected to keep increasing to 2020 and beyond: LNG; retirement of coal power plants and replacement by gas plants, methanol fertilizer plants (up to a BCF/day in new demand by the end of 2016); chemical plant feedstock (construction spending for such plants has more than doubled from 2014 to 2015; CNG and LNG for transportation (expected to continually increase as refueling infrastructure is laid out and conversion costs drop); increased usage of electric vehicles are expected to increase electricity demand and thus demand for gas; carbon emissions rules strongly favor gas over coal; increased use of small gas turbines as localized power sources. Possible reductions on demand include increased power plant efficiencies, development of smart grids and metering, better utility infrastructure planning, and increased use of renewable energy. Most of these reductions are necessary and desirable and will not have a large impact on overall gas demand in the near-term.

Market Share

In particular, the large Utica/Point Pleasant reserves may give certain well situated companies market share advantages. Range Resources and EQT just announced plans to build a large feeder pipeline in Southwestern PA. Both of these companies are well situated to take dominant market share positions with these resources. Range announced a big well in Dec. 2014 – 59MMCF/day IP in Washington County (10.9 MMCF/day/1000 ft of lateral) and more recently EQT announced an even larger one in Greene County – 72.9 MMCF/day (22+ MMCF/day/1000 ft of lateral). The EQT well had pressures greater than 8000 psi, among the highest pressure gradient seen. Consol’s recent well in Westmoreland County reportedly has an IP between EQT and Range’s wells. These wells in particular extend the major sweet spot significantly further east and lend more credibility to the high predicted reserves. Range also recently announced the highest Marcellus IP in Washington County at 43 MMCF/day. In Northeast PA Cabot and Chesapeake have dominant Marcellus positions in Susquehanna and Bradford Counties respectively. The core area companies can drill wells economically at lower commodities prices. Other market advantages include taking advantage of liquids-rich areas to increase profit and drilling multiple reservoirs at closer spacing from the same well pad, thereby sharing infrastructure. It has been suggested that Marcellus and Burket reservoirs should be drilled in tandem in the western areas where they are close together due to Marcellus producing pressures eventually affecting those of the Burket. The Burket has smaller reserves than the Marcellus but the advantages of stacked pay considerably help their economics, as does BTU boost from NGLs in the liquids fairways, although NGL prices are more tied to global oil prices so without relief from local processing facilities or long NGL pipelines current prices are likely to remain low. However, hedges and pipeline commitments are only advantageous in times of low gas prices. If demand and takeaway capacity increases as expected, hedges and pipeline commitments could work against the producers that have them as this article from BTU Analytics points out:

https://btuanalytics.com/products/a-firm-dilemma/

Supply and demand will likely continue to be a major issue in the Appalachian area as gas pricing is very sensitive to supply and demand market dynamics. Price volatility has often been problematic with natural gas but as high-reserve areas are now more delineated, things are likely to get more predictable as long as demand does not drop. The EIA predicts a 3 BCF/day (or 4%) overall rise in natural gas demand in 2015. Increasing supply has kept up with demand so far but is likely to start lagging with current low prices. Industrial consumption is expected to increase 2.3% in 2015 and 5% in 2016. Power generation and new chemical and fertilizer plants are expected to drive demand growth. Residential and commercial demand is expected to drop modestly. This article below has some interesting analysis:

http://247wallst.com/energy-business/2015/08/23/why-natural-gas-is-so-cheap-and-why-drillers-keep-producing-more/

It has also been pointed out by the EIA and market analysts that associated gas and NGL production from the shale oil plays are set to drop significantly in 2016. This should affect Appalachian supply as it reaches more distant markets.

Technological Constraints

The deep Utica/Point Pleasant dry gas play has had some significant difficulties with challenging conditions. Very high well pressures have caused difficulty in completing wells. The high vertical depths might constrain lateral lengths somewhat and increase drilling and completion times. High pressure equipment and techniques must be utilized. Safety to workers, nearby residents and to the environment is necessary. Magnum Hunter Resources has had significant difficulty turning wells in-line with one dangerous blowout in Monroe County, Ohio. In some areas of Pennsylvania where the Utica is very deep there have been drilling problems caused by caving in the Silurian salt section. Shell mentioned no problems with the Salina in northeast PA but some problems with the Bloomsburg shale below the Salina and some difficulty drilling through the hard and quartzitic Tuscaroras and Bald Eagle sandstones. This may add to well costs, especially if bit trips are required. All of these difficulties will likely slow down development to some extent until drilling and completion strategies and techniques are thoroughly worked out and best practices are developed.

Geological Constraints

One constraint to assessment is the lack of data availability for porosity mapping due to proprietary logs. Accurate porosity maps could refine reserve estimates and delineation of sweet spots. The most useful mapping at present is IP (initial potential) mapping, or better yet IP per 1000 ft of lateral. IP per frac stage is another possibility. Some isopach maps are available through the Utica Consortium and from state geological surveys. Utilizing production data, porosity, thicknesses, gas content data, log data, and pressure gradients, one can estimate resource-in-place and contour it into sweet spots. Proximity to core areas is often the key to the most economic success in these plays. Such proximity also gives better predictability so that pipeline commitments can be met and hedges made for less economic times. Unfortunately, availability of geological information is a common constraint to ideal accuracy in evaluating oil and gas as proprietary concerns are prevalent. The Utica Consortium data is useful in this respect.

  

Depositional Characteristics of the Utica/Point Pleasant/Logana Intervals

Porosity Development 

Porosity in all of these three zones appears to be entirely due to the catagenesis of organic matter from kerogen to oil and then to gas. Pores are typically very small and very little to no matrix porosity is present. High pressure aids the producibility of the resource with the exception of the oil window in central eastern Ohio which is lower pressure and as of yet has not been economically produced. However, it is clear that porosity development is the best in the so-called shelf areas of the shallow basin. The high porosity development seems to correlate very well with the core areas as investor presentations by Range, Gastar, and others have shown. This at least "suggests" some intergranular porosity by wave, storm, and/or current action, however, thin-section and core studies suggest that it may be entirely due to organic degeneration so that the high TOC areas correspond directly to the high porosity areas. There is abundant evidence of benthic fossils and bioturbation which suggest shallow oxygenated waters with bottom currents. Anoxia may have been seasonal and possibly even in successive zones just below the sea floor. There is probably more core analysis, thin-section, and petrophysical work to be done in the different zones of the overall Utica and comparison of different areas to build a better picture but enough is now known to build good drilling and completion plans.

Shell reports that the Utica-Point Pleasant equivalent play in northeast PA in Tioga County and vicinity is limited to a range 4-7% avg. porosity and very high carbonate content. They note that the high TOC shale is interbedded with the carbonate and so makes up a calcareous shale with high TOC and a high degree of brittleness. 

The Significance of Carbonate Content vs. Clay Content 

These reservoirs all average near 50% carbonate content, with the Point Pleasant and Logana > 50% carbonate. The Utica is higher in clay content and quartz while the Point Pleasant is lower in clay and higher in carbonate. The Logana is up to 75% carbonate. It is thought that the carbonate increases brittleness and allows the rock to frack better. Clay does just the opposite. In other plays where intergranular porosity is a factor the carbonate may be less brittle than the quartz. However, quartz content is very low in the Point Pleasant. The Point Pleasant is very likely the most economic unit with the most recoverable reserves. The WVGES assessment pegs it at 85.1 BCF/square mile in the average sweet spot. Porosity, high TOC, high carbonate, low clay, and high pressure are likely the main factors. The high carbonate content zones imply deposition in a shallow water basin, beginning with the initial sea level transgression in the late Trenton/Lexington.  

Zone Targeting

Most of the better wells have been targeted in the high TOC/high carbonate zones of the Point Pleasant and that will continue to be the case. A few in Ohio (apparently) have targeted the Logana (if I understood correctly) which is technically part of the upper Trenton/Lexington. The Utica shale above the Point Pleasant can be quite thick but is less prospective as a reservoir, yet it still should contain significant reserves that would be economic to produce at higher commodity prices.The Shell discovery wells slant drilled through different zones in the 200-500 ft Utica section. They have not yet determined whether there are frac barriers in the prospective section but plan to utilize microseismic at some point.