Hydraulic fracturing (fracking) is back in the news since the Ohio Department of Natural Resources indicated that it was likely that disposal of those fluids after the actual fracturing operation was likely the cause of seismic activity in the Youngstown area, the largest of which was a magnitude 4.0 on 20111231. It turns out that it us usually not the fracturing activity itself that caused the seismic, but rather deep well injection for disposal of the spent fluids after use.
This not the only potential problem with this procedure, however. I have written about the process before, but am returning to give a more in depth treatment of it. I was first drawn to the subject when earthquakes occurred in Guy, Arkansas last year. The Guy area is not known for seismic activity, but sure enough after deep well injection of the spent fluids began so did the earthquakes.
Before we look at the potential problems with this process, we should look into why it is done and some historical background. It turns out that the process is over a century old.
Hydraulic fracturing is defined as using an incompressible fluid, such as water, to cause cracks to form in (usually) rock. It was first used in granite quarries to crack blocks of granite from the parent rock without the use of explosives. In this process, holes are drilled in the rock at the proper thickness desired and high pressure water is run down them until they are filled, and then the pressure is increased until the hydrostatic pressure of the water exceeds the strength of the rock. Then it breaks cleanly away from the main mass of the rock and the water escapes. Since explosives are not used, the rock is not shattered and nice, regular blocks are produced. In practice, holes are drilled and pressurized both vertically (for thinner piece) and horizontally to separate the block from the bottom. This is a harmless process, since only water is involved in the process.
The same principle applies to hydraulic fracturing for gas (and oil) production, but it is much more complicated. It turns out that there is a LOT of natural gas in the US, but until recently it was not economical to recover. With the advent of hydraulic fracturing, this gas can now be recovered at a low enough cost to make the venture cost effective. Many of these deposits are in shale, and shale is not very permeable to gas, so when a well is drilled, the gas is very slow to enter the well and thus be recovered. With hydraulic fracturing, fluids are pumped at extremely high pressure to form cracks in the shale, and these cracks allow the gas to enter the well when the fracturing fluid is removed.
It sounds fine in principle, but water alone is not very effective for this use, unlike in the quarrying case. There are a number of reasons for this. First of all, natural gas is almost always associated with heavier hydrocarbons, and they do not mix with water. Thus, often some sort of surfactant (detergent like materials) or solvents are mixed with the water. In 2011 the US House completed a study that indicated over 750 materials are used in combination with water, and many of these are industry secrets, so neither regulators nor the general public know what they are. The list is way too long to treat in detail here, but of the additives that are known to be uses (not all additives are used in every situation), many of them are regulated under the Safe Drinking Water Act. Or, they would be if not for a very pernicious piece of legislation passed by Congress in 2005 and signed by George Bush, an oilman.
The Energy Policy Act of 2005 specifically exempted materials used for oil, gas, and geothermal energy production from the Safe Drinking Water Act, unless the materials contain diesel fuel (and some do). It turns out that Dick Cheney was instrumental in twisting enough arms in the Congress to get the exemption passed (and the huge campaign contributions from energy outfits did not hurt either), and it is often called the Halliburton Loophole since Halliburton is the largest provider of hydraulic fracturing services and of course Cheney’s association as the former CEO of the company.
Interestingly, the data used to show that this process is environmentally benign was based on coal bed hydraulic fracturing, a much less demanding kind because gas is often present in much greater concentrations in coal beds, and also because coal is in general easier to fracture that shale. Coal also tends to stay fractured where shale had the ability to “heal” and the fractures seal. There is more on that in a bit. The bottom line is that in coal bed hydraulic fracturing less fluid is required and so are lower pressures.
One of the problems involved with hydraulic fracturing is that the process is not always as controllable as we would like. Even if only pure water were used, evidence shows that in more than a few cases the fracturing proceeds to the point of invading into the water table, or even aquifers. The documentary film Gasland shows some of the consequences of this:
I must point out that Gasland is a bit sensationalized. If you notice, the water is turned to the “hot” position. I have noted this in all similar clips of burning water. Why is this important? The solubility of methane, the principal component of natural gas, is 22.7 mg/L in 20 degree C water. If a typical 50 gallon (192.5 L) water heater, that comes to 4370 mg. Using the ideal gas law, that comes to 0.27 moles, or about 6 liters. However, even at the temperature of a typical water heater is all of the methane driven out of solution. The point is, except in a case like a water heater, it is impossible to ignite water even saturated with methane. Please stay with me.
In home and in public water systems, water is pumped from the source at atmospheric pressure and put into tanks, pressurized, and distributed. It is not possible for natural gas to be present in excess of this level in 20 degree water, because it just will not dissolve. Thus, except in what I would term bizarre circumstances would it be possible to ignite tap water except where it is put in a tank and heated. When the hot water tap is opened, the pressure in the water heater is reduced from whatever the level is depending on the pressure on the house side of the water meter (or storage reservoir for home wells) and as the pressure is reduced, the methane that is there expands. Also, with the reduction in pressure the solubility of methane decreases in water, just like opening a bottle of soda. This is why there is a bit of a delay betwixt the water started and then the gas beginning to come.
Going back to our 50 gallon water heater, at atmospheric pressure the 6 liters of methane amount to a about a gallon and a half. Assuming that half of the 22.7 mg/L remains in solution in the water heater, that comes now to only about 3/4 gallon of methane. My point is that the burning water really looks spectacular but is more show than substance. Only in very special circumstances, and the only one that I than I can think of is a water heater, could this possibly happen.
This is not to say that infiltration into the water table and/or aquifers is not a bad thing, but methane is not the real problem. Since methane is lighter than air, accumulation is unlikely so the explosion hazard is really pretty low. The real danger is from infiltration is the residual hydraulic fracturing fluids themselves.
Before we get into the minutiae of fluid migration, let us consider seismic activity. It turns out that this might be the least of the threats from hydraulic fracturing, but certainly is one of the most attention grabbing ones. So far, the largest seismic event that data associate with the process is the one that we discussed previously, the 4.0 event in Ohio. In the grand scheme of things, 4.0 events are not that significant, but they certainly do get attention, and that attention is a good thing, because EVERYONE in the area affected is aware. I like for folks to be aware.
The mechanism for the seismic activity seems to be a complex interaction of the particular geology of the area, the pressures involved in injecting the waste water, and the volume of the waste injected. Normally, stable formations are chosen for deep well injection for waste disposal, but it is not always possible to ascertain when a formation is stable. Obviously completely impermeable formations are unsuitable, because there is no room for the waste water. Thus, some sort of voids have to be filled, and in many cases those involve faults that have been stable for centuries if not millenia. Injection of the waste water upsets the equilibria in those formations by a number of ways.
First, it is self evident that adding an incompressible fluid to those formations changes the static pressures of each “side” of the formation relative to the other. Because the formations are large, dynamics probably are not usually involved. However, over time the pressure differentials change. There is also another, perhaps more significant, phenomenon: many of these deep formations are relatively dry. As liquid is added, it penetrates into the dry joints in the formation and lubricates them. As they become more lubricated, the frictional forces that had held them steady for eons are reduced, and slippage is thus easier. In addition, the weight of the added liquid, if is displaces air or gas, might be significant. We shall return to this at the wrap up of the piece.
Now for the real, but less spectacular, aspects of potential damage from hydraulic fracturing. It is the additives to the water that can be responsible for lots of mischief. Here is where it gets really interesting.
The amounts of hydraulic fracturing fluids can be enormous. Typical shale wells require from 60,000 gallons to ten times that much just to get into production. That translates to from 250 short tons to 2500 short tons, just to start. Typically, another five million gallons of fluids will be required to keep a give well going, and that is just one well. That equates to 21,000 short tons of fluid! Remember, these fluids are used only for a little while, to open the fissures, because if they are left in the well, the gas can not get out of the well. So they have to be disposed of, and in massive quantities.
Now, it is finally time to consider the additives to the water. Most fluids are 98% water, but out of 21,000 short tons, even at 2% the additives amount to 840,000 pounds of additives! Most of those are pumped back out and disposed of by deep well injection, but it is impossible to recover all of them. Those additives are what go into the ground, and perhaps into the water table and aquifers. This is what worries me. Many of them are rather innocuous, but some are not. Borates are often used to soften the water, and although not highly toxic, chronic exposure can be a problem they get into well water.
Other commonly used additives are ethylene glycol, methanol, sodium hydroxide, and many others. Remember, lots of others are not even listed because they are trade secrets. Those materials, if allowed to contaminate drinking water or aquifers, are bad news. It is not the methane in the wells, but rather the additives. Remember, I also said that natural gas is often accompanied with other, heavier hydrocarbons, and then those can infiltrate water as well.
I promised to tell you about holding those fissures open after the fluids are removed. It turns out that particulate materials are often also pumped into the wells, suspended in the fluids. Those are mechanical devices, often sand, but not rarely ceramic balls, that are forced into the fissures created by the hydrostatic pressure that remain as the cracks close, holding them relatively open. They are called proppants, because they prop the fissures from collapse. They are pretty inert in themselves, but are heavy and tend to separate from the fluid. Thus, additional agents are required to keep them suspended and fast injection is important. This is also sort of disruptive.
To finish, we shall return to the disposal of the spent fluids. Since the additives make them untreatable, for the most part, in conventional sewerage systems, the are usually disposed by deep well injection as mentioned before. We talked already about changes in pressure and lubrication in the cracks where these fluids are pumped, but we have not talked about the tremendous weight of the fluids in disposal wells. Of course, one disposal well can take the waste fluids from many gas production wells. Let us say, to be conservative, that a disposal well can take the fluids from ten production wells, and that the average recovered and disposed fluid per well is 2.5 million gallons. That comes to 25 million gallons, or over a million short tons. There are only two places that this material can go.
It can either displace gases in the injection well area, or it can open fissures in the injection well. Either way, it is a net gain of over a million tons of mass, and that mass, when combined with the pressure increase and lubricity of the fluids, may well cause seismic activity. Certainly this does not occur in all cases, but the evidence is pretty clear that it does at least in some cases.
It would be incomplete not to mention the radiation associated with hydraulic fracturing. In order to visualize where the fractures are forming, industry practice is to add small amounts of a gamma emitting isotope to the fluids. With sensitive detectors, field engineers can monitor the size and direction of the fractures that are being produced during the process. A number of isotopes are used for this, most of which have half lives of only a few days or a couple of months. Those are not much of a problem, since the radiation that they produce decays away relatively quickly. However, a few that are approved have half lives measured in years so the radiation from them stays around for a long time. In general, only the shorter half life ones are used because long lived ones confuse the picture.
The reason for that is that hydraulic fracturing is a dynamic process, and isotopes with very long lives remain in previously fractured areas, making it difficult to visualize where fracturing is occurring. On the other hand, the longer lived ones do make it possible to see where fractures are closing. The radioactive isotopes do complicate the disposal of the spent fluids. Of particular concern is the use of 131iodine because if it gets into drinking water it is rapidly taken up by the thyroid gland. (This is one of the commonly used isotopes for medical diagnoses and treatments for thyroid disorders). Fortunately, this isotope has a half life of only 8 days, so the level falls off rapidly.
The bottom line is that hydraulic fracturing is not as safe as the gas companies would lead us to believe. As a scientist, I try to evaluate situations as dictated by the facts, and I believe that there are areas where this procedure can be conducted safely and effectively. I also believe that there are other areas where it is unwise to use it. In my opinion, the greatest danger is from the additives in the water infiltrating potable water sources, because they can be rendered unfit for what may be essentially forever. The radiation is not so much of a problem unless the infiltration is into potable water supplies and happens fast, since the isotopes decay to nonhazardous substances relatively rapidly. The chemical additives can linger for decades or longer.
Disposal of the spent fluids, whilst problematic, is not as great a threat as the infiltration issue, unless the deep injection wells leak into water supplies. Since it is pretty well established that at least in some cases deep well injection can cause significant seismic activity, it is at least conceivable that an injection well could contaminate water supplies. The probability of that is not very high, but it is finite.
My recommendations include the following, and I am sure that readers will be able to provide more:
Careful monitoring of water and air around wells that are undergoing hydraulic fracturing for migration of additives.
Better geological analyses of the regions where this process is planned to be used before starting the fractures.
Improved methods for disposal of spent fracturing fluids. Actually, those fluids could be used in other production wells, but since they are mainly water, it is cheaper just to dispose of them than to invest capital in storage and transportation infrastructure.
Careful seismic and chemical monitoring around all deep well injection disposal sites.
Making good use of lessons learnt from previous problems associated with hydraulic fracture and deep well disposal of spent fluids.
Hydraulic fracturing is a process that is here to stay, and I have no quarrel with it being done in a responsible manner, consistent with the science and best practices. I do not propose a universal ban on the procedure, but I do think that it can be done in a more intelligent manner. Any energy extraction process is associated with risk, but risk can be analyzed and to a large degree mitigated before even started. Only with good science and good data can that be done.
Natural gas is the cleanest fossil fuel available, if one only looks at the carbon footprint aspect. It is also certainly true that our economy is quite dependent on relatively inexpensive sources of energy. Now for a couple of pieces of bad news.
Natural gas is not very suitable as a replacement for the largest use of petroleum: fuel for automobiles and trucks. That has to do with the fact that since methane does not liquefy in a cost effective manner, at least in relatively small amounts, it is extremely difficult to compress enough of it for cars. In certain fleet services, such as buses, it can be practical, but those uses require regular routes and frequent refueling. Here is why:
A 20 gallon gasoline or diesel tank is made of thin sheet metal. Twenty gallons of gasoline in the liquid phase contains around 730 kilowatt-hours of energy. A twenty gallon, thick walled pressure vessel of compressed natural gas at 3000 psig contains only about 164 kilowatt-hours of energy. This is only a bit under a quarter of the energy in the gasoline tank, so refueling would have to happen over four time more frequently. Those tanks are heavy, too, and thus reduce efficiency because of the heavy load that the vehicle must carry. Liquified natural gas is a better option, but there are severe logistical limitations to using it. In addition, there are only around 900 or so compressed natural gas filling station in the US. I am not saying that it is not a good idea, but the infrastructure is just not here now.
Here is the other dirty little secret that the gas lobby does not publicize: the real goal is, in many cases, to export east coast natural gas for profit, NOT to use it for the domestic market. I realize that energy is a fungible resource, but when you see the adverts on TeeVee that ANGA sponsors, they universally strongly imply that this energy source will be used here, not exported. Plans are already drawn for a pipeline to supply natural gas to liquifaction plants on the east coast and then to offload the LNG on tankers for export. Do not believe everything that you see on TeeVee.
I should quit now and wait for comments. I know that this is a bit rambling, but the subject is sort of ill defined. I look forward for comments and questions so that I can elaborate.
Well, you have done it again! You have wasted many perfectly fine einsteins of photons reading this fracking piece. And even though Newt Gringrich STILL realizes that he will NEVER be President of the United States when he reads me say it, I always learn much more than I could ever hope to teach by writing this series. Thus, please keep those comments, questions, corrections, and other feedback coming. Tips and recs are also always welcome. Remember, no science or technology issue is ever off topic here. I shall hang around as long as comments warrant, and shall return tomorrow around 9:00 Eastern for Review Time.
Doc, aka Dr. David W. Smith