Marcellus+Shale

The biggest industry boom Pennsylvania has seen in over 100 years is starting to take off. We have a rock formation called the Marcellus shale under us that contains trillions of cubic feet of natural gas. Estimates on how much of this gas can be recovered vary, but the US Geological Survey has estimated it to be 84 trillion cubic feet (TCF). Since the US uses roughly 23 trillion cubic feet of natural gas per year, this is a significant source of energy. Its development has touched off many hotly debated issues, including land use, water pollution, energy independence, foreign investment, and tax revenue.





This rock formation was laid down as organic-rich sediment from 350 to 400 million years ago, when this region was under a shallow inland sea.



Eventually, this sediment was buried under millions of years of erosion material (it lies deeper than coal veins, as well) and compacted into a dense, black shale. As this occurred, the carbon-rich organic material decayed and formed microscopic gas bubbles (composed of methane, ethane, propane, etc.), which are now trapped in the rock.

Interestingly, the Marcellus shale gas also contains elevated levels of radon gas, due to the higher than normal amounts of uranium and radium also found in the shale. Geologists actually use the amount of gamma radiation emitted from shale gas to gauge its organic density. Currently, drill cuttings, piping, drilling mud, and wastewater brine are being studied to develop safety requirements in case radiation levels are too high in these materials.

The Marcellus formation has been known to geologists for decades. It was always considered to be too dense (low porosity and permeability) to be able to extract gas from it. This all changed with the development of deep-well horizontal drilling and hydraulic fracturing (fracking).



Traditional water, oil and gas wells were drilled vertically, and were designed to puncture a reservoir. Because the surface area of a vertical well is so small, it is not a practical method with Marcellus shale. This shale formation must be approached horizontally to maximize surface area.



Marcellus shale can also be fractured along the horizontal plane (termed fissility). It has natural fractures, which can be taken advantage of.



In order to extract the gas from the shale's fractures and pores, it is hydraulically fractured using water, sand, and trace amounts of other chemicals (called frac fluid). The fluid also contains a friction reducer (lubricant), which is why the phrase "slickwater" hydraulic fracturing is used. A typical horizontal well requires 500,000 to a few million gallons of frack fluid to do the job.



"Fracking" is done by pumping the frac fluid into a well to pressures in the thousands (sometimes tens of thousands) of pounds per square inch. This causes the shale to fracture, and forces sand grains (known as proppant) into the fissures. When the water is removed, the sand holds the fissures open. This allows the gas to be extracted from the shale much more efficiently.

Here are a couple links to the PA Department of Environmental Protection's recent releases concerning frac fluids:
 * Chemicals Used by Hydraulic Fracturing Companies in Pennsylvania
 * Summary of hydraulic Fracturing ingredients

The following image links to a video that demonstrates the horizontal drilling and hydraulic fracturing techniques used on the Marcellus shale formation.



The high-volume slickwater hydraulic fracturing process requires tens of thousands of horsepower; many pumping trucks must be operating simultaneously in order to achieve the pressure. The frack fluid is stored in container trucks on-site before, during, and sometimes after this process. This process lasts anywhere from one to three weeks.




 * Waste Water**

As soon as the fracking process is complete, the fracking fluid is under pressure and some (an estimated 40-60%) of it will return to the surface. This fluid is called //flowback//, and is typically pumped into storage containers, where it will be trucked to a disposal facility, or if the drilling company recycles it, treated and most likely re-used at the next frack job.

Flowback volumes vary from well to well, but range from a few hundred thousand to a few million gallons. Most of the flowback exits the well in a time period of a few days to a few weeks.

As soon as flowback is complete, the well may then produce water that is either naturally occurring from aquifers, or leftover flowback water, for up to the lifetime of the well (60+ years). This water is aptly named //produced water//. It is typically a more concentrated brine, containing high levels of TDS (total dissolved solids), heavy metals, and radionuclides (e. g. radum-226). As the well ages, the volume of produced water typically declines, and the concentration of salts increases.

Both the flowback and produced waters from deep oil and gas wells such as those drilled into the Marcellus formation can pose an environmental challenge to gas companies, water treatment facilities, and government regulatory agencies. These waters represent the largest waste stream volume that these companies have to deal with.

These fluids have been found to contain:
 * some hydrocarbons (organic compounds from drilling/fracking process or from the shale itself)
 * high levels of total dissolved solids (TDS), primarily sodium, chloride, and bromide ions
 * concentrations of heavy metals such as barium
 * elevated levels of radioisotopes such as radium-226


 * Treatment of Liquid Wastes**

Some municipal waste water treatment facilities (known as sewage treatment plants) have been accepting drilling waste fluids as long as its volume does not exceed 1% of the daily total water volume. Even so, concerns have been raised because these traditional municipal waste water treatment facilities (POTWs) are not designed to handle flowback and produced water. The high concentrations of TDS could interfere with normal operating conditions of these treatment plants; they are incapable of removing salts or treating organic hydrocarbons; and some of these plants discharge into streams and rivers that lead to drinking water facilities. Here, bromides in the waste water can form carcinogenic trihalomethanes when the water is treated with chlorine. Recently, PA DEP moved to stop allowing POTWs to accept Marcellus waste fluids. Much of this waste fluid is being trucked to Ohio for storage in deep injection wells.

These fluids need to be treated by specialized brine treatment facilities. A few drilling companies are recycling the waste stream, however, in order to save disposal costs.



In order to re-use the frack water, flowback, and produced water, it usually has to be treated on-site. This can be done in a number of ways, involving chemical treatment and physical separation techniques.

Some companies are pre-treating waste water so that it can be recycled or disposed of at brine treatment plants. Most pre-treatment is done by vacuum distillation, where the water is evaporated at low pressures from the liquids and removed, leaving behind a solid sludge. The water is reuseable; the sludge must be disposed of properly.



Other pretreatment methods include:
 * VOC reduction and hydrocarbon removal
 * reverse osmosis
 * filtration membranes/zeolite ion exchangers
 * capacitive deionization (uses charge separation to remove ions)
 * vacuum distillation
 * electrodialysis

These methods are ideally done to flowback water on-site by portable, vehicle-mounted machinery if the water is to be re-used. This is not practical for treatment of produced water, which will come out of the well over its gas-producing lifetime. Produced water must be trucked or piped to brine treatment facilities.

The solid wastes obtained through gas well production include drill cuttings, drilling mud, sludge from fluid treatment and storage tanks, pipe casings, and construction material. These wastes are generally disposed of in approved landfills. In some cases, solids such as drill cuttings and mud are stored on-site in a lined pond, capped, and buried.
 * Solid Waste**



Because deep geologic formations contain elevated levels of uranium and its radioactive decay products (such as thorium, radium and radon), there is the potential for radiation exposure when working with the waste products from deep gas and oil well production. These radionuclides can dissolve in fracking fluid and will return to the surface with the fluid, flowback, and produced water. As mentioned earlier, deep, horizontally drilled and hydrofractured wells have the potential to bring high levels of radioactive materials to the surface.
 * Radiation Issues**

Sludge from produced water, whether it be from treatment or settlement in brine tanks, can contain elevated levels of radionuclides. The most concerning is radium-226 due to its solubility and long half-life (1,600 years), and bioaccumulation potential. Landfills in Pennsylvania now have radiation alarms that will detect radioactive material before it enters the facilities. These are mainly after medical and industrial nuclear waste, but they have also been set off by waste from oil and gas industries.

Natural gas that originates from these deep formations also contain radon gas. Radon-222 is a decay product of thorium, and has a half-life of 3.8 days. This gas does not typically pose a problem when it is in storage lines, for it usually remains in these lines well beyond a few half-life cycles. The real problem lies in the fact that when it undergoes radioactive decay, it becomes a solid again (the most long-lived product being lead-210, with a half-life of 22.3 years). These radionuclides will settle inside the piping and pipe scale, and within brine storage tanks. Worker exposure to these materials can pose a health risk and a challenge to their handling and disposal.


 * Gas Preparation and Storage**

Once the natural gas is able to flow or be pumped out of the well, it must be treated and purified. This usually involves removal of water vapor (drying the gas) in a dehydrator. Water vapor is removed so that it does not form ice crystal hydrates or condense on the interior of pipelines. The methods of water removal include dehydration via temperature drop (similar to a household dehumidifier) and via liquid or solid dessicants (which absorb and hold water).



Another treatment that the gas must go through is removal of sulfur-containing compounds, so that the gas meets certain air quality control standards. Sulfur in any fuel causes odor, corrosion, and the exhaust can eventually produce acid rain. The removal process is called desulfurization. The gas is filtered through an activated carbon medium that will trap and remove sulfur-containing compounds.



Other gas purification steps may include removal of carbon dioxide or other unwanted organic compounds.


 * Gas Compression**

Once the gas is clean, it heads to a compressor station. Here, the gas is pressurized and sent into storage or transport pipelines at pressures ranging from 200 to 1500 psi.



Inside these compressor stations are the gas compressors themselves - very large diesel engines that do the work.



This is essentially the final step in natural gas production on the well head end. The natural gas is transported through a national network of pipelines to its final destination, which could be an electricity generating power plant, an industry, or a residence.

Here is an aerial photo of a Marcellus gas production site that is near completion. The well pads have been restored, but the water reservoir has not.



**Potential Energy Impact Assessment**