Water management options associated with the production of shale gas by hydraulic fracturing
Authors: Kelvin B. Gregory1, Radisav D. Vidic2, and David A. Dzombak1
1Department of Civil and Environmental Engineering, Carnegie Mellon University, Pittsburgh
2Department of Civil and Environmental Engineering, University of Pittsburgh, Pittsburgh
Published: March 14, 2012
This text is part of the article “Water Management Challenges Associated with the Production of Shale Gas by Hydraulic Fracturing” that was originally published in Elements, Vol. 7, June 2011. Rights reserved by the publisher.
Introduction
The grand challenge that natural gas producers must address is how to preserve the favorable economics of shale gas production while maintaining responsible stewardship of natural resources and protecting public health. The goals of the natural gas developers and the goals of those responsible for human and environmental health protection are intimately connected by water, including its use, management, and disposal.
Water Resources
The drilling and completion of wells require large quantities of water. Drilling of the vertical and horizontal components of a well may require 400 - 4000 m3 of water for drilling fluids to maintain downhole hydrostatic pressure, cool the drillhead, and remove drill cuttings. Then, 7000 - 18,000 m3 of water are needed for hydraulic fracturing of each well. These large volumes of water are typically obtained from nearby surface waters or pumped from a municipal source. In regions where local, natural water sources are scarce or dedicated to other uses, the limited availability of water may be a significant impediment to gas resource development.
Management of Flowback Water
Flowback of the fracturing fluid occurs over a few days to a few weeks following hydraulic fracturing, depending on the geology and geomechanics of the formation. The highest rate of flowback occurs on the first day, and the rate diminishes over time; the typical initial rate may be as high as 1000 m3/d (GWPC and ALL Consulting 2009). The composition of the flowback water changes as a function of the time the water flowing out of the shale formation was in contact with the formation.
Minerals and organic constituents present in the formation dissolve into the fracturing water, creating a brine solution that includes high concentrations of salts, metals, oils, greases, and soluble organic compounds, both volatile and semivolatile (Tab 2). The flowback water is typically impounded at the surface for subsequent disposal, treatment, or reuse. Due to the large water volume, the high concentration of dissolved solids, and the complex physicochemical composition of the flowback water, there is growing public concern about management of this water because of the potential for human health and environmental impacts associated with an accidental release of flowback water into the environment (Kargbo et al. 2010).
Treatment technologies and management strategies for flowback water are based on constraints established by governments, economics, technology performance, and the appropriateness of a technology for a particular water. Past experience with produced and flowback waters is used to guide developers towards treatment and management options in regions of new production (Kargbo et al. 2010). Flowback water management options for some shale plays, such as the Marcellus, are confounded by high concentrations of total dissolved solids in the flowback water, geography, geology, and a lack of physical infrastructure (Arthur et al. 2008; Kargbo et al. 2010).
Underground Injection
Most produced water from oil and gas production in the United States is disposed of through deep underground injection (Clark and Veil 2009). When underground injection is utilized, such operations are performed using Class II (disposal) underground injection control wells as defined by the U.S. Environmental Protection Agency (Veil et al. 2004).
However, the availability of adequate deep-well disposal capacity can be an important constraining factor for shale gas development. In Texas, there were over 11,000 Class II disposal wells in 2008, or slightly more than one disposal well per gas-producing well in the Barnett Shale (Tintera 2008). In contrast, the whole state of Pennsylvania has only seven Class II disposal wells available for receiving flowback water. The Marcellus Shale is a large resource that will eventually be exploited by a large number of producing wells.
Although the number of underground-injection disposal wells in Pennsylvania is expected to increase, shale gas development is currently occurring in many areas where insufficient disposal wells are available, and the construction of new disposal wells is complex, time consuming, and costly (Arthur et al. 2008). As a result, other solutions for flowback water management are necessary.
Discharge to Publicly Owned Treatment Works (POTWs) for Dilution Disposal
Although discharge and dilution of flowback water into publicly owned municipal wastewater treatment plants (POTWs) has been utilized (e.g. Penn Future 2010), this is not an adequate or sustainable approach for managing flowback water. The amount of high-TDS flowback water that can be accepted by POTWs is usually limited by regulation.
For example, in many POTWs in Pennsylvania, the amount of oil and gas wastewater must not exceed 1% of the average daily volume of waste handled by the POTW. In addition, discharge limits in Pennsylvania for TDS are set at 500 mg/L to insure the quality of the processed product. In general, the volume of flowback water that can be sent to POTWs is small compared to the volume of flowback water generated during rapid well drilling and well development.
Reverse Osmosis
Reverse osmosis (RO) is a well-known treatment method for producing drinking water and high-purity industrial water. In the RO process, water is passed through a semi-permeable membrane under pressure and a treated water of high quality is produced, along with a concentrate that requires disposal. This separation process removes material ranging from suspended particulates down to organic molecules and even monovalent ions of salt (Xu and Drewes 2006).
In trials of RO treatment of flowback water, the volume of concentrate for disposal has been reduced to as low as 20% of the initial volume of flowback water (ALL Consulting 2003). Driven by mechanical pressure, RO is energy intensive. Even with favorable energy prices, the treatment of flowback water using RO is considered to be economically infeasible for waters containing more than 40,000 mg/L TDS (Cline et al. 2009).
For high-TDS waters, vibratory shear-enhanced processing (VSEP) has been applied to membrane technologies (Jaffrin 2008). In VSEP, flat membranes are arranged as parallel discs separated by gaskets. Shear is created by vibrating a leaf element tangent to the membrane surface. The created shear lifts solids and fouling material off the membrane surface, thereby reducing colloidal fouling and polarization of the membrane (New Logic Research 2004). VSEP technology has been used successfully in the treatment of produced water from offshore oil production (Fakhru’l-Razi et al. 2009). However, the salt concentrations in offshore produced waters are far lower than those expected during shale gas extraction.
Thermal Distillation and Crystallization
The high concentrations of TDS in flowback water may limit the use of membrane technology, but such water is well suited to treatment by distillation and crystallization (Doran and Leong 2000). Distillation and crystallization are mature technologies that rely on evaporating the waste-water to separate the water from its dissolved constituents.
The vapor stream is passed through a heat exchanger to condense the gas and produce purified water. Distillation removes up to 99.5% of dissolved solids and has been estimated to reduce treatment and disposal costs by as much as 75% for produced water from shale oil development (ALL Consulting 2003). However, as with RO, distillation is an energy-intensive process.
Thermal distillation may treat flowback water containing up to, and in some cases even exceeding, 125,000 mg/L of TDS, but even the most modern technology is limited to low flow rates (300 m3/d), necessitating the construction of large storage impoundments (Veil 2008). For example, flowback water from the Marcellus Shale gas sites can be produced at rates of 3000 m3/d or higher.
Recent developments include using mechanical vapor-recompression systems to concentrate flowback water, which can be done at a fraction of the cost of conventional distillation because the heat of the compressed vapor is used to preheat the influent. Further water evaporation to create dry mineral crystals (i.e. crystallization) will improve water recovery and create salt products that might be reused as industrial feed stocks. Crystallization is a feasible approach for treating flowback water with TDS concentrations as high as 300,000 mg/L, but it has high energy requirements and large capital costs.
Other Treatment Options
Several other technologies have been or are being developed for treating flowback water, but each has its limitations. Falling into this category are ion exchange and capacitive deionization (Jurenka 2007), which are limited to the treatment of low-TDS water; freeze–thaw evaporation, which is restricted to cold climates; evaporation ponds, which are restricted to arid climates; and artificial wetlands and agricultural reuse (Veil et al. 2004), which are greatly limited by the salinity tolerance of plant and animal life.
On-Site Reuse for Hydraulic Fracturing
One of the most promising technologies for management of flowback water is its reuse in subsequent hydraulic fracturing operations. Flowback water is impounded at the surface and reused either directly or following dilution or pretreatment. Reuse is particularly attractive in regions where deep-well disposal options are limited or where the availability of make-up water for hydraulic fracturing is limited.
The reuse of flowback water has the benefit of minimizing the volume of such water that must be treated or disposed of and greatly reduces environmental risks while enhancing the economics of shale gas extraction. Potentially limiting factors for reuse are the chemical stability of the viscosity modifiers and other constituents of hydraulic fracture water in the brine solution and the potential for precipitation of divalent cations in the well-bore.
The effectiveness of friction reducers may be decreased at high TDS concentrations (Kamel and Shah 2009). The development of additives that retain their effectiveness in brine solutions are likely to expand the opportunity for reuse of flowback water for subsequent hydraulic fracturing. The divalent cations in the flowback water are solubilized from formation minerals and can form stable carbonate and sulfate precipitates in the wellbore if the flowback water is reinjected.
This may potentially reduce gas production from the well. In particular, barium and strontium form very low-solubility solids with sulfate, while high calcium concentrations may lead to calcite formation. Depending on the quality of the flowback water, pretreatment to reduce the divalent cation concentration by precipitation may be necessary.
References
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