Produced Waters

and captured (fig. 1).

Figure 1. Simplified illustration of a coalbed
methane production well. (Modified from Rice and
Nuccio, 2000 by Eric A. Morrissey, USGS.)

Water generated from CBM production is typically re-injected into a different unit, treated, beneficially used and/or directly discharged into ponds or surface waters. The USGS and colleagues are involved in examining environmental impacts from several different disposal/beneficial use strategies for CBM Produced Waters.

One area of focus is the Powder River Basin (PRB) in Wyoming and Montana, the second largest producer of CBM in the United States. Coalbed methane activities within the Wyoming portion of the basin currently generate 570-680 million bbls of water per year (1bbl = 42 gallons), little of which is reinjected into the subsurface. The CBM produced waters from the PRB are Na-HCO₃ type waters and contain relatively low concentrations of trace metals (Rice and others; 2000). However, some of the water samples collected from the basin exhibit low to moderate total dissolved solid concentrations (370-1,940 mg/L) and a relatively high sodium adsorption ratio (SAR=5.7-32). Direct discharge of these waters to the surface has the potential to damage soils and ecosystems. Additionally, infiltration of CBM waters have been shown to leach pre-existing salts from the unsaturated zone, and in some cases lead to high salinity plumes in shallow groundwater.

Figure 2. Cartoon showing hypothetical
distribution of water and salts in a working

SDI system employing CBM produced water,

Powder River Basin.

One method for using CBM produced water is the irrigation of crops via subsurface drip irrigation (fig. 2). However, few data exist which examine potential impacts from this technology. To better understand impacts of salt and water derived from CBM produced waters on a SDI system, the USGS and colleagues are investigating through application of geochemical and geophysical tools. Additionally, because CBM produced waters are derived from a coal, an organic-rich substance, they often contain elevated levels of organic compounds. Organic compounds are indicative of energy sources potentially available for biological organisms to potentially generate additional CBM, through biogenic processes. Alternately, some of these compounds are toxicants and may present environmental concerns. Therefore further work is being conducted to better understand the behavior and distribution of organic compounds in CBM produced waters.

References

Rice, C.A. and Nuccio, V., 2000, Water Produced with Coalbed Methane: U.S. Geological Survey Fact Sheet FS-156-00. 

Rice, C.A., Ellis, M.S., and Bullock, J.H., Jr., 2000, Water co-produced with coalbed methane in the Powder River Basin, Wyoming: preliminary compositional data: U.S. Geological Survey Open-File Report 00-372, 20 p.

Figure 1. Locations of wells in the Appalachian Basin

from which produced water samples were collected

and analyzed. Data from Breit (2002) and Osborn

and McIntosh (2010).

total dissolved solids; sea water is ~35,000 mg/L TDS). Initially, data from a variety of sources, including state and federal agencies, and possibly private sources, is being surveyed to compile basic information on the natural components of the deep groundwater. This information should be useful in advance planning for the disposal or possible recycling of produced formation water and flowback water. This information should be useful in advance planning for the disposal or possible recycling of produced formation water and flowback water.

A primary source of produced water geochemistry is a database compiled by Breit (2002) for localities throughout the United States, including 90 samples from the Appalachian Basin (fig. 1). The database reports the major cations and anions (i.e., Na, Ca, K, Mg, Cl, HCO₃, and SO₄) as well as mass and charge balance, pH, and total dissolved solids (TDS). The salinities of the Appalachian Basin produced waters compiled by Breit (2002) have a median of 246,000 mg/L TDS (fig. 2), markedly higher than for produced waters from almost all other oil and gas producing regions of the United States. The Rocky Mountain and Colorado Plateau regions, for example, have a median produced water salinity of 9000 mg/L TDS. The Appalachian Basin samples are predominantly Na-Cl-type waters; Ca is significant, but secondary to Na both in molality and equivalence. Concentrations of Mg, K, SO₄ and HCO₃, are minor to insignificant (fig. 3).

Figure 2. Boxplot comparing distribution of TDS

of water samples collected from the
Appalachian Basin and three western United

States basins. The upper and lower limits of

the box indicate the 1st and 3rd quartiles, the

median (2nd quartile) is denoted by the

horizontal line in the box. The 5th and 95th

percentiles are noted by the upper and lower

bars, respectively, on the whiskers.

 

Figure 3. Piper diagram showing range of

composition (percent equivalence) of water

samples collected from the Appalachian Basin.

The plot suggests that most produced waters

generated from the basin are Na-Cl

dominated waters, but that some variations

exist. Data from Breit (2002).

Figure 4. Plot of TDS versus reservoir age for water samples

collected from the Appalachian Basin. Data from Breit (2002).

The waters in a given reservoir are most commonly a mix of fluids from multiple horizons that have migrated varying distances through the basin over geologic time. In some cases however, reservoir fluid represent connate water, or the fluid originally trapped during deposition of the reservoir strata. The Appalachian Basin samples of Breit (2002) were obtained from reservoirs of Pennsylvanian through Cambrian age, with a majority from Silurian and Devonian reservoirs (fig. 4). Overall, these samples are not sufficiently evenly distributed throughout the stratigraphic section to permit conclusions as to reservoir age vs. salinity.

The USGS is investigating additional sources of data beyond the database of Breit (2002) in order to address the following long term objectives:

• Characterization of the major element chemistry of formation waters to define geographic trends in salinity, and/or trends relative to reservoir age. Possible new sample locations and types of analyses should be investigated.
• Identification of salinity sources (e.g., evaporite dissolution vs. connate water). This may help in predicting approximate salinity levels by reservoir age and location.
• Characterization of the sources and concentrations of NORM (naturally occurring radioactive material) and TENORM (technologically enhanced naturally occurring radioactive material) in formation waters and produced waters across the Appalachian Basin.

Figure 1. This drill rig, outside of Parshall, North

Dakota, targets the Bakken Formation at a

depth of approximately 14,000 feet.

increase fluid conductivity of the reservoir unit through hydraulic fracturing (commonly called “fracing”). Fracing fluids must be removed prior to resource extraction. These returned fracing fluids, known as flowback water, generally contains salts and minerals from the formation in addition to the additives used to increase fracing efficiency. The large volumes of water involved in these practices (generally 1-5 million gallons per frac job) have already led to supply and disposal problems in some areas. To address such issues and to help stakeholders prepare appropriately, the USGS is developing water-budget methods for uses associated with oil and gas production. Established USGS energy assessments provide estimates of technically recoverable resources. These results will be extended to project the volume of water needed for hydrocarbon production.

Figure 2. Digital elevation model showing locations of

wells producing oil from the Bakken Formation (red dots).

The blue line shows the boundary of the Bakken

Formation, the red line shows the boundary of the

Williston Basin, and the green lines denotes the

approximate extent of the prairie potholes region. Data

source: IHS database.

The Williston Basin in Montana and North Dakota (fig. 2) is the area of our initial focus because of (1) the large quantity of oil present in the Bakken Formation, and (2) the potential for impacts on the Prairie Pothole wetlands that host large numbers of migrating waterfowl. Current, rapidly escalating production of Bakken Formation oil a million or more gallons of fresh water per well for fracing. Historic and ongoing conventional oil production from other Williston Basin formations has resulted in large volumes of highly saline produced waters; in the past, some of these waters escaped into shallow aquifers and have impacted wetlands. USGS scientists are estimating the quantities of water (fracing and produced) that would be involved in a range of future hydrocarbon production scenarios and comparing these quantities with estimated total water budgets for the region.