Flowback and Produced Waters by unknow

Author:unknow
Language: eng
Format: epub
Tags: Earth Sciences: Water and Hydrology
Publisher: National Academies Press
Published: 2017-03-02T21:00:00+00:00

FIGURE 5.2 Projected and to-date water demand for hydraulic fracturing in the eagle ford shale play.

NOTE: HF = hydraulic fracturing.

SOURCE: Scanlon, slide 4.

Using the commercial IHS database, their work found that the top 95 percent of fluid types that were reported to be injected into wells were gels, foam-based fluids, and slickwater. In areas associated with shale gas production, the majority of fluids reported were actually slickwater-based fluids, she said. In other areas, which were primarily producing tight oil, they saw that the fluid types were mostly gel-based fluids, while in coal-bed methane areas, injected fluids were largely foam-based fluids, often created using carbon dioxide and nitrogen gases. What is injected into a well during hydraulic fracturing is important when examining the potential use of flowback waters, Gallegos noted.

The USGS describes “produced water” as well fluid that is co-produced with oil or gas, Gallegos continued. Generally, the fluid collected at the wellhead shows three phases. The head space contains gas, which is largely methane. Below the head space is an oil phase, which is separated from an underlying layer of water. The water contains a variety of different constituents, she said. One of the big challenges when examining produced waters is the ability to measure the constituents. Waters have very high salinity and a high specific gravity, and they are also very corrosive. The range of constituents makes the fluids challenging analytically—instruments tend to clog, tubing can corrode, and dilution of water is required, Gallegos said. Dilution presents a problem when trying to detect the presence of trace elements, for example, arsenic or radium.

Another aspect regarding analytical characterization of the fluids is the difficulty in obtaining basic parameters, for example, pH. Calibration is difficult due to lack of comparable buffer solutions, which generate interferences that impact instruments. Difficulties with measuring organics and inorganics are similarly challenged as analytical standard solutions are not in an equivalent matrix. The USGS is trying to develop a brine laboratory to specialize in measuring high-salinity solutions, she indicated.

Gallegos then described various aspects of the USGS produced waters database. The database contains about 165,000 different samples from different wells across the United States and is essentially a collection of about 33 different databases that have been compiled with quality assurance and control over the years. The database has recently added trace elements and is also beginning to include isotopes. Initially, the database consisted of conventional wells, but unconventional wells including coal-bed methane, shale gas, tight oil, tight gas, and some geothermal wells have been incorporated, she said. Not every constituent is available for each data point, but the data often include TDS, pH, calcium, and trace metals such as arsenic, mercury, and cadmium. Other constituents in the database are boron, calcium, magnesium, chloride, and sodium. One of the take-home points Gallegos emphasized was the range of concentrations for a given constituent from produced wells regionally, or even within the same basin. Two of the constituents that are not as well populated in the produced waters database are radium and organics.

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