31 July 2013
The Ins and Outs of Fracking and Underground Waste Injection Wells
Posted by John Freeland
When the Akron Beacon-Journal Online publishes its updated interactive map of active, permitted, and producing oil and gas wells in Ohio, it places another map right below it. The second map shows underground waste injection wells. These two maps belong together because underground injection wells are used to dispose of the polluted flowback water from high volume hydraulic fracturing (fracking) operations.
When thinking about potential for groundwater contamination, hydrofractured oil/gas wells and underground waste injection wells differ in an important aspect. While “frack” wells use pressurized fluids and sand to force open fissures in shale rock, the fluid pressure is released during “flowback.” The ultimate goal of fracking is extraction of valuable hydrocarbons from the shale. Brine usually comes up along with the oil and gas. Extraction reduces the fluid pressure in the rock formation and well casing.
Where does injected waste go?
In the case of waste injection wells, there’s no “flowback” unless there’s a failure. The goal is to push junk down the well and never see it again. Unlike oil/gas frack wells, there’s no reversal in pressure to extract valuable materials from the rock formation receiving the waste. It’s a one-way trip down the well with the very real potential of building up pressure as more waste is injected.
The porous rock formations that are used for deep waste injection contain void spaces that are usually filled with saline water. Usually, the deeper one samples groundwater, the saltier it gets. Saltier water is more dense than less salty water.
The groundwater mostly found in deep injection formations is unfit to drink even prior to the injection of wastes. Information about depth to saline groundwater is available through the USGS and depicted on the generalized map below. According to the map, saline ground water in Ohio is found at less than 500-feet below the ground surface. Utica shale oil/gas wells and deep waste injection wells are thousands of feet deep.
The problem with the deep saline groundwater isn’t just saltiness. As noted by the USGS, “Saline ground water also may contain some constituents, such as arsenic, elevated radioactivity, and dissolved organic material…”
What worries me about underground waste injection is that the waste is not being injected into a vacuum. In order to get fluid into a rock pore, whatever fluid is already there has to move out. Where does it go?
Earthquakes and New Regulations
A series of twelve small earthquakes (2.1-4.0 on the Richter Scale) within a mile of an injection well in Youngstown, OH has been attributed to frack waste injection.
The Youngstown earthquakes and the follow-up investigation have prompted some new regulations from the Ohio Department of Natural Resources, which is allowed by the EPA to administer the regulatory program for injection wells in the state. One of the provisions is to monitor pressures within the wells and shut them down when maximum allowable pressures are exceeded.
The use of underground injection to dispose of waste has been around since the 1930s. The United States EPA regulates six different classes of injection wells under its Underground Injection Control (UIC) Program. The different classes “are based on similarity in the fluids injected, activities, construction, injection depth, design, and operating techniques.” Details are available at the EPA UIC Program website.
The wells receiving waste brines from oil and gas production wells are Class II wells. According to the EPA, there are 172,068 such wells in the United States.
Sensitive to regulatory and public concerns, as well as likely rising costs for disposal, energy companies are apparently taking steps to reduce, re-use, and recycle water used for fracking. However, both water supply and waste disposal remain big headaches for the industry.
A joint online effort, called fracfocus.org was started by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission to provide a registry of information on an individual oil/gas well basis, across the United States.
What the Akron Beacon-Journal publishes is a good start, but I’d like to see more information made available about the underground waste injection wells. Would it be feasible to publicly disclose and make available online a registry including detailed logs of what kinds, when, and how much waste was pumped down a given waste injection well? How often are the wells inspected? Maybe such records exist. I’m still looking.
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.
Mr Freeland. I am an Environmental Engineer, and I am currently researching on shale gas environmental regulation for Argentina, as a part of my Msc. Thesis. Today I was precisely wondering about the topic you are talking about. In my humble opinion, the most important risk for aquifers is a failure in the cementing process. I have read some information stating that about 60% of the wells (all kind of wells) have some failure regarding cementing and this kind of failures may lead to the proliferation of gaps in the annular space between the pipe and the well, leading to a possible contamination of an aquifer. Hence it is of utmost importance to control how the companies are doing the cementation process: Which cement are they using (since injection wells are known for being “low tech” it may not be surprising to find a higher rate of failure). It is also important, as you said, to find where does the original saline water go when it is moved by the injection. I think that if there are several geomechanical discontinuities between the injection depth and the aquifer depth (several sandstone and shale layers), the probability of this fluid to get into aquifers is negligible. Conspicously, the deeper the well, the more expensive it is. So I infer that companies will be prone to inject their water in shallow formations, which are closer to aquifers. This topic is very interesting. I look forward to read more about this from you.
Mr. Melo:
Thanks for writing. You raise several good points. I’m not in the well drilling/completion business, but I think your point about the improper cementing found in failed wells has been documented numerous times. Like you, I suspect the waste injection wells are older, and vary a great deal in terms of quality of construction and present structural integrity. I worry about them more than the hydrofractured oil/gas wells.
I would like to see a thorough well inventory, testing and monitoring program at the state or federal level with the staffing, training, budget, and accountability necessary to know what’s going on with those wells and protect water resources. The program should be transparent and records should be made easily available to the public, in my opinion.
Regarding your comment: “if there are several geomechanical discontinuities between the injection depth and the aquifer depth (several sandstone and shale layers), the probability of this fluid to get into aquifers is negligible.”
Suppose you have:
1. A drilling log with lithologies described according to depth.
2. You see there are several layers of shale and sandstone and the vertical distance between the aquifer receiving waste and the nearest public water supply aquiver is thousands of feet.
3. You create a groundwater flow model, factoring in the various hydraulic and chemical gradients, and assume standard conductivity rates for shale and sandstone.
4. Based on the low hydraulic conductivity rates of the shale, and the thousands of feet of distance, you may find that it would take thousands of years for the waste to seep into the water supply aquifer.
The problem with the above scenario is it doesn’t take into account preferential flow through macropores: rock faults and fractures, other nearby wells, etc. Have the rocks been mapped well enough to account for these features? I doubt it.
Finally, the well casings are built to withstand certain maximum pressures. Are pressures monitored and verified? What do operators and regulators do if there is a sudden change in pressure? I believe Ohio has a new regulation that shuts down a disposal well when pressures get too high. What happens if there is a sudden decrease in pressure indicating a rupture in the well casing or confining rock layer? Do they shut down then? I’m looking for more information.
I would have starred the two last paragraphs of your comments, Mr. Freeland. They are what most concern me.
As an old Cementer, a man whose job was to cement off the water zones in oil wells , it has a whole lot of things that can and do go wrong. We will start with the grout or cement, they make it as cheap as they can, fly ash is a large part of the mix, compare a cinder block to a poured concrete wall and the difference is evident. Voids, need I say more. Areas where the groundwater is flowing are common. Mechanical malfunctions of the pumping equipment during the cement job, half done so they pour a bit on the top to cover it up, the inspector sees a nice outflow trail .
Keep up the good fight, Professor, regulation and strict oversight are the only way the oil field players are ever going to follow the rules . How many out of thousand citizens understand any of this? It’s not even one in a thousand…
Norm: Thanks again for bringing your experience and sage advice to this dialogue. I’d like to think that a calculation of risk vs. reward would motivate the companies to use the very best grout and cementing practices. Sounds like that’s not the case. How much are they really saving on cheap cement? Then again, even for highly profitable companies, it’s somebody’s job to constantly look for additional cost savings. This kind of thinking sometimes reaches a point of negative return.
The poster child for penny saving was the Gulf Spill, BP had: it boiled down to not enough centering baskets in the ‘long string’ cement job. The production pipe laid up against the edge of the bore and no cement was able to reach those areas. The reservoir had 68,000 psi on it; it pushed past the voids…
Haliburton told BP that they needed the full number of baskets for a proper cement job but someone at BP decided to save a few bucks. Irony is not reserved for fiction.
Incredible. Thanks again, Norm.
By vacuum I assume he means empty. Very poor term to use in this instance. A water glass can be empty, but cannot have a vacuum. The well is either empty or has oil in it. There is no other “stuff” that is being forced out. You cannot inject anything into a vacuum. As soon as you open the vacuum to injection it ceases to be a vacuum.
I’m guessing the rest of the article is also just made up junk science. He is just assumning facts and thinks he has the intelligence to make up for research and study. If one paragraph is bogus then the rest of the article is suspect.