25 September 2011
The Top-Down Risk of Hydrofracturing
Posted by John Freeland
ExxonMobile commercials fail to address flowback fluids.
ExxonMobile geologist Erik Oswald is becoming quite a media “star.” As a fellow geologist, I think this is great. Erik’s on-camara presence is warm, friendly, competent, and, most importantly, reassuring. I have no doubt that’s exactly how he is in real life.
What Erik describes in Exxon commercials with respect to 1.5 mile vertical distance and engineered borehole barriers between the gas formation and near-surface aquifers is true enough but I take serious issue with his following comment, which he makes in the commercial linked above:
“Most wells are over a mile and a half deep, so there’s a tremendous amount of protective rock between the fracking operation and the groundwater.”
The above statement implies that the threat of groundwater contamination comes from a mile and a half below, and that the well is effectively sealed to prevent upward migration of contaminants associated with the deep shale gas formation. However, in most cases of groundwater contamination, with some important exceptions, the aquifer is threatened from above, not from below.
Flowback and Brine Contamination
Hydrofracturing involves pumping millions of gallons of fluid comprised of water, sand, and chemicals down a hole under tremendous pressure. Before gas can come out of the well, most of the fluid flows back up to the surface as brine containing some other junk picked up from the shale, some of which is toxic. This fluid is then usually stored in ponds prior to disposal.
Earlier this year, Dr. Conrad Volz of the University of Pittsburgh gave this testimony to the U.S. Senate Committee on Environment and Public Works and its Subcommittee on Water and Wildlife, Joint Hearing “Natural Gas Drilling, Public Health and Environmental Impacts”, April 12, 2011. Dr. Volz described hazardous aspects of flowback water this way:
(The third problem is) the disposal of gas extraction flowback fluids, carrying a plethora of toxic elements and chemicals, in inefficient “brine” treatment facilities and Publicly Owned Treatment Works (POTW’s) [commonly called sewage treatment plants], which discharge effluent into surface water sources. Studies of the effluent from a commercial facility in Pennsylvania that treats fluids only from gas and oil operations shows discharge of 9 pollutants in excess of nationally recognized human and/or aquatic health standards into a
nearby stream. The contaminants include:• Barium, found in effluent over 8 times its minimum risk level (MRL) in drinking water to children and 27 times its EPA consumption concentrations for fish and “fish plus water”.
• Stable Strontium, found in effluent 43.29, 51.68 and 97.90 times the drinking water MRL’s for intermediate exposures for adult men, adult women, and children, respectively. Strontium levels found in effluent were 29,811 times the reporting limit in the plants NPDES permit.
• Bromide, which forms mixed chloro-bromo byproducts in water treatment facilities that have been linked to cancer and other health problems were found in effluent at 10,688 times the levels generally found acceptable as a background in surface water.
• Benzene, a known carcinogen, is present in effluent water at over 2 times its drinking water standard, over 6 times its EPA consumption criteria, and 1.5 times the drinking water MRL for chronic exposure for children.
• 2-butoxyethanol (2-BE), a glycol ether and used as an antifoaming and anticorrosion agent in slick-water formulations for Marcellus Shale gas extraction was found in effluent water at 24.48, 29.21, and 55.14 times the drinking water MRL’s for intermediate exposure to adult males, adult females, and children, respectively –based on hepatic health effects.
• Chlorides, the concentration of chlorides in the effluent was 138 and 511 times the EPA maximum and continuous concentration criteria set for the health of aquatic organisms, respectively.
I don’t blame Erik Oswald for omitting the part about flowback water in his commercials. I put that on his employer, ExxonMobile. And, I’m not opposed to hydrofracturing to extract natural gas. In fact, I’m in favor of it as I previously wrote here, if it is done with adequate environmental regulations and enforcement.
Companies like ExxonMobile and others need to face the water supply and quality issues associated with hydrofracturing head-on.Pretending they don’t exist doesn’t serve their long-term interests or those of society. Solutions to the technical problems of hydrofracturing are achievable, as far as I can tell. Until we commit to truly “doing this right,” we won’t see the full benefits of developing this domestic energy resource.
John Freeland earned a PhD in Soil Science (Pedology) at North Dakota State University and is a consultant working in the private sector. He has published soils research and taught at the high school and college levels. John is interested in wetlands, soil genesis, science communication, the intersection of art and science, and soil-water-landscape processes. John lives near the Ohio-Michigan border and plays bass in multiple music projects.
The problem is a captured regulatory system, the money that pays the watchdogs comes from drilling fees, an inherent conflict. Funding the inspectors out of a state’s general fund would make them more independent and less likely to get in bed with their funding base. A 24-7 work crew would help as well, the oil fields are not 9 to 5, iffy cement jobs get run at night or on the weekend if there is any indication of voids or running water in the cement zone. (less drilling mud returning than is going down the bore)
Independent regulators are the key to safe practice in any industry but even more so in an industry that operates in the boondocks. Out of sight out of mind.
Thanks for your comment, which makes a lot of sense.
I’m a big fan of the new drilling system, less mess on the surface, much cheaper in the long run and safer because we drill fewer holes. Our current political mindset is that regulation is bad, with the drilling people that is foolish thinking, their standard reply when something goes south is:prove it! And that is not easy. Regulation is needed or we are going to see a witch hunt when we get our first salted up city water well. We need to develop these new fields. There are many old fields that were over pumped over a hundred years ago that can be made productive again with the new drilling system, again safeguards must be used. The old fields have many unplugged holes, practice was to just cut off as much pipe as you could shake loose from the hole and walk away. We can produce off those old fields again but it has to be regulated.
Here in Michigan, companies are installing arrays of monitoring wells and collecting baseline groundwater data prior to commencement of drilling.
Here in Pennsylvania, we’ve had those storage ponds overflow, contaminating private property, with the drilling company denying the problem. Even when confronted with photographic evidence.
We have residents water wells contaminated with natural gas, literally, flammable water. The drilling company’s solution: Provide bottled water to the resident. Makes for a GREAT shower!
Now, how could such things happen, with a lined well?
The drill is of a certain diameter. The casing, slightly less. There will be voids between the actual bore of the well and the liner at random intervals, due to the nature of the strata. In some areas, it is possible for voids to become cumulative in a collective weakness. It’s possible for an incorrect liner being chosen. Even drilling errors can create issues where gas can flow upward to the aquifer. Once gas can flow, liquid can flow as well, even fracturing compound. The converse is also possible.
When one considers human nature, one realizes that many would be tempted to not report a release of either product or fracturing compound. It’s less hassle.
So, I am firmly of the belief of significant regulation AND oversight on the regulators.
To do otherwise is to risk the drinking water supply AND our natural gas supply.
Actually what Erik is saying about fracing is entirely correct in almost all basins and plays in which hydrofracing occurs. I cannot speak for procedures in Pennsylvania and the Marcellus; however, in almost all of the basins where hydrofracing occurs there is miles of formation between the fraced zones and shallow groundwater.
Also, the statement above that most of the fluid comes back is not really accurate. There are a lot of factors and different formations, pressures, treatments, etc., may apply but generally most or at least a large fraction of the fluid remains in the formation after the well is fraced.
As I mentioned, i can’t speak for Pennsylvania; however, in many areas, such as down here in Texas, there are strict requirements for flowing back into surface pits. Any pit for flowback water has to be permitted and the construction has to be done under a PE’s supervision. Pit liners, annual integrity testing, leachate monitoring and groundwater monitoring are all required for the permitting of a pit to be used for flowback. Generally, pits are not used and the water is collected in tanks and then hauled off for disposal downhole in standard injection wells.
No doubt there are places where the major danger of contamination is associated with “other” activities associated with fracing…such as pits, or improperly plugged and abondoned wells or wells with casing leaks. These however are not the direct result of fracing itself….they are “collateral” issues that can be addressed by proper construction and permitting procedures.
The problem isn’t the “miles of formation” between the aquifer and resource, but a combination of TYPE of formation, quality of bore, quality of lining (if any, at depth) and dozens of other factors.
Compared to oil, natural gas flows MUCH more easily around obstructions (such as liners). Whatever leakage that has occurred in Pennsylvania is minor, but present sufficiently to contaminate wells within a quarter mile of a well on several occasions.
I do agree, a vast amount of that compound remains deep below ground, where it shouldn’t cause harm. It’s not like some Sci-Fi movie where it’ll come alive and climb out! 🙂
But, what IS left on the surface remains a concern, as contractors are known to cut corners, if permitted to.
Here in Pennsylvania, we have moderately strict regulations, but very few inspectors. We tend to regulate by commission and conflicts of many form occur on a regular basis, a fundamental flaw in many of Pennsylvania commission regulated industries, politics comes into play as well. But, the heart remains funding of inspectors to enforce any standard adopted. Again, a fall-down on the part of the Commonwealth, rather than anything else.
Honestly, I doubt anything will change by any significant amount in Pennsylvania until, perhaps, the Gateway National Recreational Area has a mass kill in the Delaware watershed or some similar situation. Regulatory systems have slipped significantly since the mid-70’s in many areas, indeed, smog is even returning to a mild level here.
But, I’ve not witnessed nor heard of tank usage, other than for transport, only lined open storage ponds are in use, which have either leaked or overflowed after rain. Several private ponds are now under the “care” of the drilling company, as they were sterilized (OK, all animal life was gone from them) after compound from the storage pond made its way into that private pond.
I’ll agree entirely with the latter point, assuming effective supervision and inspection, which requires more than 3-8 inspectors per region. Ineffective, undermanned enforcement means zero enforcement and violations would be unabated.
Frankly, if *I* owned or leased such a resource, I’d not want ANY leakage for one reason, it’s wasting my money. Either my compound that I paid for is permitted to leak away or my product is permitted to leak away. But then, I prefer six sigma in operations, much higher profit for only a moderate increase in operational expenses.
Your comments are well noted. No doubt the state agencies that are tasked with field inspecting and ensuring the integrity of surface pits are short-staffed on overworked. Even down here in Texas in our local TRRC districts there have been mass exoduses of seasoned field personnel as budgets have been slashed and cut. This has led to inexperienced,demoralized, and not enough field personnel to adequately take on the task.
Any serious and established operatoring O&G company does have their own staffs (I am a Sr. Staff Env. Specialist for a large independent) and they would of course be looking our for their companies own liability risks. Any company, such as mine, is serious about our responsibilities and corporate ethics…..we take regulatory compliance extremely serious and we do not tolerate non-compliance. We also understand that in order to sustain our activities we must be active in looking at ways to do our business in a manner that does not affect the communities in which we work and live.
As a past President of the American Association of Petroleum Geologists, Division of Environmental Geosciences, I can tell you that this organization has many members from many different stakeholder groups….including government agencies, universities, state agencies and of course industry that are working hard on addressing many of these issues.
It still sounds like many of the issues up there are “collateral” to the actual physical action of fracing….and that these issues are in the storage and transportation of the fluids. I hope that the operators are not “slacking” off due to a lack of inspectors and that they are doing the correct and diligent things that a good and prudent operator should be doing to protect the environment and any impacts to health.
Most of us who work for O&G companies live in the communities that we have operations and we are as much a part of the community as anyone else. We do not want to do anything that would harm our own family as we would our neighbors and friends. My company has production facilities on the golf courses….in residential areas, and in sensitive areas. We have a very competent staff of environmental professionals including environmental engineers, geologists and hydrogeologists and we take our responsibities of protecting the environment very seriousy….as does the management all the way to the top. Most serious operators will have similar staffs. But, there are always some operators who may “cut” corners. However, there are those sorts in any kind of business, and unfortunately the whole is often judged by the few.
Clearly, running a clean operation is in the long-term best interests of the industry. Still, too often, too many skip the checklist. From talking to environmental scientists in Pennsylvania, it seems the big problem is flowback water – what to do with it. They’re trying to recycle for multiple frackings and letting it evaporate in ponds. They also send it to water treatment plants and Class II injection wells in Ohio, which is costly. If we used more natural gas for transportation, starting with semi trucks and buses instead of dirty diesel, the price of natural gas would likely go up and help offset the cost of better technology to treat the frack water.
I am seeing stories about Propane being used to carry the sand into the formation instead of water. The blowback will be worth enough that “spilling ” it might not be profitable.
Interesting.
No doubt It is in everyone’s interest to run a clean operation.
Flowback water is an issue, particularly where you don’t have Class II disposal wells to send it to. Trucking is the largest expense in regards to both produced water and flowback water. Pits should be considered as the last resort; however, most likely not all operators have nearby disposal wells, and if I recollects there are just a few Class II wells in Pennsylvania. This is quite a contrast whereas my company has over 100 SWD’s here in Permain alone.
We have a number of “pilot” projects running to look at not only treating flowback water for re-use but also looking at using produced water for drilling and fracing. The issue with produced water is not the salinity but it is other constituents such a boron, manganese and some other constituents that mess up the cross linkers and gels.
As for the “propane” fracks, there are some operators who are looking into this and I am not that familiar with it….but it is my understanding that it is not as good of a procedure as the liquid fracs.
Thanks for the input! I have zero information on what constitutes fracing compound (OK, not zero, but close enough).
That considered, perhaps injection into Centralia, right into the core of the fire?
It’d dehydrate the mess AND dispose of the mess AND be in an unused water source.
The bore wouldn’t have to be substantial, due to the nature of the excess AND temperature of the fire zone.
THEN, we’d have a new mine over time, one for those elements sought, percolated by water, into usable veins.
Rather than have pools getting rained on and flooding the local lands.
Just an idea, perhaps someone with experience in the fields involved could improve upon it.
A liquid is a liquid, how propane reacts with additives that are designed for water is a different matter but it can be done. Here in Ohio the new play is in a shale deposit that is rich in “wet gas”, the local paper has reports of as much as 14% propane by volume. This may enhance the development of new additives and methods for these new wells development. I’m sure the kids at Dow are puttering around the lab with this matter as we chat.
The more liquid rich wet gas shales are preferrable to the dry gas shales. Keep in mind that the fracing fluids are injected into these hydrocarbon bearing zones…which of course of in themselves toxic, unless folks want to start drinking BTEX and lower chain hydrocarbons. Micro-seismic is conducted during fracing to ensure that the frac zone stays within the producing zone.
I guess my issue here is that what is coming out of the ground following the frac flowback is what we use to fuel our cars, heat our homes, etc., etc., etc. We are living in the “hydrocarbon age” and we enjoy all of the benefits we derive from it. We all….even us in the industry enjoy our trips to the desert southwest…..the pacific northwest….and the northeast….and we all either drive our cars…take a plane….or take a boat out to do our whalewatching.
The point is that we are all trying our best to develop these resources in a responsible way so that we may continue to enjoy the freedoms and benefits that this abundant source of energy provides us.
As technology advances….and economics for alternative methods of fracing evolve so will the safety of the process.
For those who may be interested in learning more about Hydrofracking…I include the following
“Hydrofracking 101: What Is It, What Are The Issues, and How Can Geophysics Help?” 2012 Symposium on the Application of Geophysics to Engineering and Environmental Problems (SAGEEP), Tucson Arizona
Dr. Bruce Smith (USGS Denver), Dr. Jeffrey Paine and Dr. Chip Groat (Bureau of Economic Geology-University of Texas Austin) and myself are co-convening a full day workshop on hydrofracing which will be held at the EEGS annual convention in March in Tucson. This workshop is also being co-sponsored by the AAPG/Division of Environmental Geosciences. Below are some of the major topics that will be presented and discussed.
■Hydrofracking Impact and Policy Issues
■What is Hydrofracking?
■Hydrofracking Issues from the Industry Perspective
■Hydrofracking Issues from the Regulatory Perspective
■Regional Water Needs, Availability, and Impact
■Geophysical Microseismic Monitoring
■Induced Seismicity?
■Geophysical Case Histories
■Geophysical Approaches to Address Hydrofracking Issues
Attached below is a link to the website. We are inviting anyone interested in participation or attending to review the website and contact us.
Mike Jacobs ([email protected]), Chip Groat ([email protected]), Jeff Paine ([email protected]), and Bruce Smith ([email protected]).
Link….
http://www.eegs.org/annualmeetingsageep/sageep2012.aspx
Thanks Mike. Sounds like a good conference.
Well John….. the following is a “Draft” agenda of the workshop as it has shaped up.
Hydrofracturing 101: What Is It, What Are The Issues, and How Can Geophysics Help?
Thursday, March 29, 2012, Tucson, Arizona
Morning Session (8 a.m. to 12 noon): Hydrofracturing Issues, Policy, and Needs
Introductions and Logistics – Mike Jacobs, Pioneer Natural Resources; Chip Groat, University of Texas, Austin; Jeff Paine, University of Texas, Bureau of Economic Geology, Austin; Bruce Smith, USGS, Crustal Imaging Center, Denver
Hydrofracturing Impact and Policy Issues – Chip Groat, University of Texas , Austin
What is Hydrofracturing? – Hal Macartney, Pioneer Natural Resources
Hydrofracturing Issues from the Industry Perspective; An Example from the Permian Basin -Mike Jacobs, Pioneer Natural Resources
Water Supplies for Hydraulic Fracturing: A Look at Anticipated Water Demand Associated with Bakken and Eagle Ford Production – Seth Haines, USGS, and J. P. Nicot, University of Texas/BEG
Induced Seismicity ? Bill Foxall, Louis Livermore National Laboratories
Dam Safety Implications of Drilling, Hydrofracturing, Injection, and Extraction – Anita Branch, USACE
The Power of a Map; Using Geospatial Analysis to Communicate Hydraulic Fracturing Public Policy
Issues – Jess B. Kozman, Mining & Minerals
Moderated Discussion on Hydrofracturing Policy, Issues, and Monitoring Needs – ALL
Lunch (12 – 1; provided on site)
Afternoon Session (1 to 5:00 p.m.): Geophysical Monitoring and Assessment
Modeling and Microseismic Monitoring of Hydraulic Fractures in Shales: Linking the Physics of Fracturing to the Geophysics of Monitoring – Mark Mack, Schlumberger
Passive Microseismic Monitoring (title tbd) ? Mike Mueller, Microseismic
Hydraulic Fracture Height Growth – Shawn Maxwell, Schlumberger
Microseismic Monitoring of Hydraulic Fracturing for Unconventional Oil and Gas Plays – Julie Shemeta, MEQ Geo Inc.
Geophysical Approaches – Thomas L. Dobecki
The Potential for Rapid Electrical Monitoring to Hydraulic Fracturing – Dale Rucker, Hydrogeophysics
Geophysical Logging for Characterization of Hydrogeologic Framework and Delineation of Freshwater, Saltwater, and Gas in Fractured Upper Devonian Bedrock above the Marcellus Shale – John H. Williams, USGS
Examples of Characterization, Evaluation, and Monitoring for CO2 Sequestration Applicable to Hydrofracturing – Garrett Veloski and others, US Department of Energy, Pittsburgh
Examples of Applications of Electrical Conductivity Mapping and Monitoring for Groundwater Quality in Areas of Energy Production Bruce Smith, USGS and others
Moderated Discussion on Geophysical Approaches to Regulatory, Monitoring, and Impact Issues ALL
Mike:
I’m sorry for not posting this comment sooner. I just fished it out of the spam folder. It looks like a good line-up for the conference.