Geology topics

Joanna N. Thamke

Publications and source records attributed to Joanna N. Thamke.

At least 19 recordsLinked to original sources

USGS2022

Potential effects of energy development on environmental resources of the Williston Basin in Montana, North Dakota, and South Dakota—Physiography, climate, land use, and demographics

The Williston Basin has been a leading domestic oil and gas producing region. As energy demands have increased, so has energy development. A group of 13 Federal agencies and Tribal groups formed the Bakken Federal Executive Group to address common challenges associated with energy development, with a focus on understanding the cumulative environmental challenges attributed to oil and gas development throughout the basin. To better understand the natural resources in the Williston Basin, the U.S. Geological Survey, in cooperation with the Bureau of Land Management, began work to synthesize existing information on science topics that will support management decisions related to energy development. This report is a compilation of information regarding the natural setting, energy development history, demographics, and related investigations related to energy development in the Williston Basin of Montana, North Dakota, and South Dakota. Completed and ongoing investigations include the topical areas of unconventional oil and gas assessments, water quality, water availability, air quality, effects on human health, and ecological effects.

Montana, North Dakota, South Dakota↗

USGS2021

Estimates of water use associated with continuous oil and gas development in the Permian Basin, Texas and New Mexico, 2010–19, with comparisons to the Williston Basin, North Dakota and Montana

The Permian Basin, in west Texas and southeastern New Mexico is one of the largest conventional oil and gas reservoirs in the United States and is becoming one of the world’s largest continuous oil and gas (COG) reservoirs. Advances in technology have enabled oil and gas to be extracted from reservoirs that historically were developed using conventional, or vertical, well drilling techniques. Conventional oil and gas reservoirs have discrete deposits that are well defined and are typically trapped by an overlying geologic formation or caprock, whereas COG reservoirs contain deposits that are distributed evenly throughout the geologic formation, typically have much lower permeability (the capacity of a porous rock to transmit a fluid) than the conventional deposits, and require specialized horizontal extraction techniques. The methods to extract the oil from the two different reservoirs require differing amounts of water, and the horizontal extraction methods typically require substantially more water. In 2015, the U.S. Geological Survey started a topical study to quantify water used during COG development. The Permian Basin, which contains both types of reservoirs (continuous and conventional), was the second basin in the United States in the U.S. Geological Survey’s topical study to quantify water used during COG development.

Montana, New Mexico, North Dakota, Texas↗

USGS2021

Estimates of water use associated with continuous oil and gas development in the Permian Basin, Texas and New Mexico, 2010–19

In 2015, the U.S. Geological Survey started a topical study to quantify water use in areas of continuous oil and gas (COG) development. The first phase of the study was completed in 2019 and analyzed the Williston Basin. The second phase of the study analyzed the Permian Basin using the same techniques and approaches used for the Williston Basin analysis. The Permian Basin was selected for the second phase of water-use analysis for the following reasons: (1) the basin has the largest undiscovered technically recoverable oil and gas resource in the United States, (2) the basin has a continuous resource in tight shale that primarily produces oil, and (3) the basin is within the contiguous United States. This study used data from 60 counties in Texas and New Mexico with spatial coverage based on the Permian Basin extent defined by the U.S. Energy Information Administration, a representation of the geologically defined Permian Basin. Data from several sources were used in the analysis of direct, indirect, and ancillary water use associated with COG development in the Permian Basin and are available in an associated data release. Hydraulic fracturing water-use data were used to determine the start of the recent (before 2019) COG development boom in oil production in the Permian Basin in the same way that the data were used for the Williston Basin study. Water-use data were aggregated by county and year, which were the sampling units used in the analysis. The water-use analysis of the Permian Basin contained three elements: (1) estimates of water use, in million gallons, by county and year; (2) coefficients of water use from regression models, in million gallons per developed oil and gas well; and (3) performance (based on goodness-of-fit metrics) of the regression models in estimating the observed water use. Coefficients from the linear and quantile regression models of direct, indirect, and ancillary water use in the Permian Basin were produced as aggregate values for the counties and years. The mean estimate of direct water use had a 95-percent confidence interval of 4.13–5.45 million gallons (Mgal) per developed oil and gas well. The coefficient from the linear regression model of indirect water use was 0.111 Mgal per well, with a 95-percent confidence interval of 0.104–0.117 Mgal per well. The mean estimate of ancillary water use in the Permian Basin was 1.09 Mgal per well, with a 95-percent confidence interval of 1.05–1.13 Mgal per well. Model performance was evaluated with goodness-of-fit metrics including coefficient of determination ( R 2 ), root mean square error, and the ratio of root mean square error to standard deviation of observations computed from leave-one-out cross validation of the linear and quantile regression models of direct, indirect, and ancillary water use. Model performance for direct water use was acceptable, with an R 2 value of 0.91. The model performance of indirect water use was acceptable, with an R 2 value of 0.89. Values of R 2 for the ancillary water-use categories were at least 0.89. Annual mean estimates for hydraulic fracturing, cementing, drilling, indirect, and ancillary water use per well for the years 2010–17 were comparable between the Permian and Williston Basins. Hydraulic fracturing water use increased similarly from 2010 to 2015 in the Permian Basin and the Williston Basin, increasing from 0.6 Mgal per well in 2010 to 5.4 Mgal per well in 2015 in the Permian Basin and from 1.4 Mgal per well in 2010 to 4.7 Mgal per well in 2015 in the Williston Basin. By design, the Permian water-use assessment is a simplification of a complex and continually developing system and therefore has uncertainty and limitations in the interpretation of results. Despite the modeling limitations, the results summarized in the report, when compared to other studies, compare well with water-use estimations. The favorable comparison highlights the transferability of the water-use methodology to other areas of COG development.

New Mexico, Texas↗

USGS2020

Estimates of water use associated with continuous oil and gas development in the Williston Basin, North Dakota and Montana, 2007–17

This study of water use associated with development of continuous oil and gas resources in the Williston Basin is intended to provide a preliminary model-based analysis of water use in major regions of production of continuous oil and gas resources in the United States. Direct, indirect, and ancillary water use associated with development of continuous oil and gas resources in the Williston Basin was estimated in North Dakota and Montana from 2007 to 2017. Water-use data were aggregated by county and year, which were the sampling units used in this analysis. Linear and quantile regression models of water use in relation to the number of oil and gas wells developed were fit for the direct, indirect, and ancillary water-use categories for each State. A 95-percent confidence interval for each parameter estimate from the linear regression models was computed as a measure of uncertainty. Additional information on uncertainty can be gained from modeling other distribution parameters, so quantile regression models of the 5th, 50th, and 95th percentiles also were fit. To assess uncertainty in the estimates from the regression models of direct, indirect, and ancillary water use, leave-one-out cross-validation was used. Model performance was evaluated with three goodness-of-fit metrics used to compare the estimates and observations of water use. Mean annual direct and indirect water use for development of continuous oil and gas resources in North Dakota was estimated at 4,512 million gallons (Mgal) per year (Mgal/yr), with a 95-percent confidence interval of 4,021–5,152 Mgal/yr, and in Montana was estimated at 196 Mgal/yr, with a 95-percent confidence interval of 189–203 Mgal/yr. Ancillary water use (for domestic and public supply) had an estimated annual mean of 2,753 Mgal/yr in North Dakota and 396 Mgal/yr in Montana. The coefficient from the linear regression model of direct water use was 3.86 Mgal per well and hydraulic fracturing water use was 3.70 Mgal per well for North Dakota. The mean estimate of direct water use had a 95-percent confidence interval of 3.48–4.23 Mgal per well. For North Dakota, the coefficient from the linear regression model of indirect water use was 0.453 Mgal per well, with a 95-percent confidence interval of 0.415–0.492 Mgal per well. Direct and indirect water use had a mean estimate of about 4.31 Mgal per well in North Dakota. The mean estimate of ancillary water use (for domestic and public supply) in North Dakota was 2.03 Mgal per well, with a 95-percent confidence interval of 1.76–2.31 Mgal per well. For Montana, the linear regression model of hydraulic fracturing water use had a mean estimate of 2.04 Mgal per well. The 95-percent confidence interval for the mean estimate was 1.80–2.28 Mgal per well. Direct and indirect water use in Montana had a mean estimate of 2.49 Mgal per well. The mean estimate of ancillary water use (for domestic and public supply) in Montana was 2.43 Mgal per well, with a 95-percent confidence interval of 1.76–3.11 Mgal per well.

Montana, North Dakota, South Dakota↗

USGS2019

Analytical framework to estimate water use associated with continuous oil and gas development

An analytical framework was designed to estimate water use associated with continuous oil and gas (COG) development in support of the U.S. Geological Survey Water Availability and Use Science Program. This framework was developed to better understand the relation between the production of COG resources for energy and the amount of water needed to sustain this type of energy development in the United States. The total mean undiscovered, technically recoverable volume of COG has increased, highlighting the continued need to develop approaches to better characterize water use associated with COG development. The analytical framework can be used to estimate water use associated with COG development for three water-use components—direct, indirect, and ancillary water use—that are related to the life cycle of COG development. Direct water use is defined as water used in a wellbore to complete a well, including the water used for drilling, cementing, stimulating, and maintaining the well during production. Indirect water use is the water used at or near the well site, including water used for dust abatement, for cleaning equipment, and for crew and staff use. Ancillary water use is all other water used during the life cycle of COG development that is not categorized as direct or indirect, such as additional local or regional water use resulting from a change (for example, population) related to COG development. The analytical framework includes the data inputs, the processes involved in estimating the water-use coefficients and analyzing their uncertainties, and the outputs. The analytical framework was developed as an R script, which contains the statistical models used to estimate water-use components. The availability of data across COG reservoirs in the United States is variable and presents challenges for estimating water use for extracting COG from their reservoirs; thus, the R script can be modified for the types of data available within a COG reservoir, the extent and resolution of data available for each water-use component, and the desired output of the water-use assessment. The script was written so that the units of the data in the script were standardized. Water-use estimates were simulated for the mean and 10th, 50th, and 90th percentiles of the data distributions. Uncertainties were quantified with confidence intervals for the estimated coefficients. Uncertainty for estimated or simulated data can be calculated with the R script by providing a range of representative values that are within the appropriate confidence intervals of the mean of the data.

Lower 48 states↗

USGS2019

Predicting attenuation of salinized surface- and groundwater-resources from legacy energy development in the Prairie Pothole Region

Oil and gas (energy) development in the Williston Basin, which partly underlies the Prairie Pothole Region in central North America, has helped meet U.S. energy demand for decades. Historical handling and disposal practices of saline wastewater co-produced during energy development resulted in salinization of surface and groundwater at numerous legacy energy sites. Thirty years of monitoring (1988–2018) at Goose Lake, which has been producing since the 1960s, documents long-term spatial and temporal changes in water quality from legacy energy development. Surface water quality was highly variable and decoupled from changes in groundwater quality, likely due to annual and regional climatic fluctuations. Therefore, changes in surface water-quality were not considered a reliable indicator of subsurface chloride migration. However, chloride concentrations in monitoring wells near wastewater sources exhibited systematic temporal reductions allowing for estimates of the time required for natural attenuation of groundwater to U.S. Environmental Protection Agency acute and chronic chloride toxicity benchmarks and a local background level. Point attenuation rates differed based on sediment type (outwash vs till) and yielded a range of predicted years when water-quality targets will be reached: acute – 2045 to 2113; chronic – 2069 to 2160; background – 2126 to 2275. Bulk attenuation rates from four separate years of data were used to calculate the distances chloride could migrate downgradient from the largest wastewater source. Potential distances of downgradient migration before dilution to water-quality targets decreased from 1989 to 2018: acute – 949 to 673 m; chronic – 1220 to 922 m; background – 1878 to 1525 m. Several downgradient wetlands are within these distances and will continue to receive saline contaminated groundwater for years. While these results demonstrate chloride attenuation at a legacy energy site, they also highlight the persistence of saline wastewater contamination and the need to mitigate future spills to prevent long-term salinization from energy development.

Montana↗

USGS2018

Williston Basin groundwater availability, United States and Canada

The Williston Basin contains important oil and gas resources for the Nation. Freshwater supplies are limited in this semiarid area, and oil and gas development can require large volumes of freshwater. Groundwater is the primary source of water for many water users in the Williston Basin, so to better understand these resources, the U.S. Geological Survey (USGS) assessed the groundwater availability in this area. The final phase of this assessment included a computer model that simulates how groundwater flows in the aquifer systems and simulates how changes in water use and natural conditions may affect the water resources. These results provide a tool for land and water-resource managers to determine how water can be used for multiple purposes in the Williston Basin. For additional information about this assessment and more in-depth descriptions and results, see Long and others (2018).

Williston Basin↗

USGS2018

Groundwater availability of the Williston Basin, United States and Canada

Executive Summary The Williston Basin of the Northern Great Plains is a sedimentary basin—a geologic bowl-like structure filled with layered sedimentary rocks dating as far back as the Paleozoic age. The basin, which is nationally important for the production of energy resources, spans Montana, North Dakota, and South Dakota in the United States, and Manitoba and Saskatchewan in Canada. The three uppermost principal aquifer systems are the glacial, lower Tertiary, and Upper Cretaceous aquifer systems. As deep as 3,000 feet (ft) at the center of the basin, these are the most accessible aquifer systems in the basin and are the primary sources of potable groundwater in much of this area. The glacial aquifer system consists of Quaternary-age unconsolidated till, silt, clay, outwash sand and gravel, and occasional cobbles and boulders. The lower Tertiary and Upper Cretaceous aquifer systems consist primarily of sandstone, siltstone, mudstone, shale, and coal. As energy demands have increased in the basin, horizontal drilling and hydraulic-fracturing have been used (especially since 2005) to develop previously inaccessible formations—namely, the Bakken and Three Forks Formations. The basin has yielded a large supply of domestic oil and natural gas since the 1950s, but the technologies required to extract those materials use large amounts of freshwater. The increasing freshwater demands of energy production in the Williston Basin, in addition to population growth, have led to a need for new tools to assess groundwater resources.

Williston Basin↗

USGS2017

Assessment of water and proppant quantities associated with petroleum production from the Bakken and Three Forks Formations, Williston Basin Province, Montana and North Dakota, 2016

The U.S. Geological Survey (USGS) has completed an assessment of water and proppant requirements and water production associated with the possible future production of undiscovered oil and gas resources in the Three Forks and Bakken Formations (Late Devonian to Early Mississippian) of the Williston Basin Province in Montana and North Dakota. This water and proppant assessment is directly linked to the geology-based assessment of the undiscovered, technically recoverable continuous oil and gas resources that is described in USGS Fact Sheet 2013–3013.

Montana, North Dakota↗

USGS2017

Characterization and origin of brines from the Bakken-Three Forks petroleum system in the Williston Basin, USA

Brine (also referred to as ‘produced water’) samples were collected from 28 wells producing oil from the Late Devonian-Early Mississippian Bakken and Three Forks Formations in the Williston Basin of eastern Montana and western North Dakota. The samples were analyzed for major ions, trace metals, stable isotopes, and strontium isotopes. The brines in these formations are highly saline with total dissolved solids averaging 308 g/L, almost ten times the salinity of modern seawater. Relative to modern seawater, the brines are enriched approximately 10 to 20 times in [Na], [K], [Cl], and [Br]. Greater enrichments of 100 to 400 times in [Li], [B], [Sr] and [Rb], and 2,000 to 10,000 times in [Cs] and [Ba] are probably due to water-rock interaction (WRI). WRI is further indicated by 87Sr/86Sr values typically between 0.710 and 0.711—considerably larger than marine values of 0.7081 to 0.7083 during this depositional interval. Bakken Formation sediments were deposited in a stratified water column with salinity increasing with depth. The deeper water may have been saturated in calcium carbonate and possibly gypsum, but there is no evidence that halite saturation had been attained. Therefore, brines may have been introduced into the Bakken Formation from the underlying Devonian Prairie Formation or from the overlying Charles Formation before these brines were diluted or replaced by meteoric water. Alternatively, salinity of the native pore water was increased by membrane filtration driven by overpressuring within the Bakken Formation.

Mountain Geologist↗

USGS2016

Estimating national water use associated with unconventional oil and gas development

The U.S. Geological Survey’s (USGS) Water Availability and Use Science Program (WAUSP) goals are to provide a more accurate assessment of the status of the water resources of the United States and assist in the determination of the quantity and quality of water that is available for beneficial uses. These assessments would identify long-term trends or changes in water availability since the 1950s in the United States and help to develop the basis for an improved ability to forecast water avail- ability for future economic, energy-production, and environmental uses. The National Water Census ( http://water.usgs.gov/watercensus/ ), a research program of the WAUSP, supports studies to develop new water accounting tools and assess water availability at the regional and national scales. Studies supported by this program target focus areas with identified water availability concerns and topical science themes related to the use of water within a specific type of environmental setting. The topical study described in this fact sheet will focus on understanding the relation between production of unconventional oil and gas (UOG) for energy and the water needed to produce and sustain this type of energy development. This relation applies to the life-cycle of renewable and nonrenewable forms of UOG energy and includes extraction, production, refinement, delivery, and disposal of waste byproducts. Water-use data and models derived from this topical study will be applied to other similar oil and gas plays within the United States to help resource managers assess and account for water used or needed in these areas. Additionally, the results from this topical study will be used to further refine the methods used in compiling water-use data for selected categories (for example, mining, domestic self-supplied, public supply, and wastewater) in the USGS’s 5-year national water-use estimates reports ( http://water.usgs.gov/watuse/ ).

Fact Sheet↗

USGS2016

Chemical and isotopic changes in Williston Basin brines during long-term oil production: An example from the Poplar dome, Montana

Brine samples were collected from 30 conventional oil wells producing mostly from the Charles Formation of the Madison Group in the East and Northwest Poplar oil fields on the Fort Peck Indian Reservation, Montana. Dissolved concentrations of major ions, trace metals, Sr isotopes, and stable isotopes (oxygen and hydrogen) were analyzed to compare with a brine contaminant that affected groundwater northeast of the town of Poplar. Two groups of brine compositions, designated group I and group II, are identified on the basis of chemistry and 87 Sr/ 86 Sr ratios. The solute chemistry and Sr isotopic composition of group I brines are consistent with long-term residency in Mississippian carbonate rocks, and brines similar to these contaminated the groundwater. Group II brines probably resided in clastic rocks younger than the Mississippian limestones before moving into the Poplar dome to replenish the long-term fluid extraction from the Charles Formation. Collapse of strata at the crest of the Poplar dome resulting from dissolution of Charles salt in the early Paleogene probably developed pathways for the ingress of group II brines from overlying clastic aquifers into the Charles reservoir. Such changes in brine chemistry associated with long-term oil production may be a widespread phenomenon in the Williston Basin.

Montana↗

USGS2014

Borehole geophysical data for the East Poplar oil field area, Fort Peck Indian Reservation, northeastern Montana, 1993, 2004, and 2005

Areas of high electrical conductivity in shallow aquifers in the East Poplar oil field area were delineated by the U.S. Geological Survey (USGS), in cooperation with the Fort Peck Assiniboine and Sioux Tribes, in order to interpret areas of saline-water contamination. Ground, airborne, and borehole geophysical data were collected in the East Poplar oil field area from 1992 through 2005 as part of this delineation. This report presents borehole geophysical data for thirty-two wells that were collected during 1993, 2004, and 2005 in the East Poplar oil field study area. Natural-gamma and induction instruments were used to provide information about the lithology and conductivity of the soil, rock, and water matrix adjacent to and within the wells. The well logs were also collected to provide subsurface controls for interpretation of a helicopter electromagnetic survey flown over most of the East Poplar oil field in 2004. The objective of the USGS studies was to improve understanding of aquifer hydrogeology particularly in regard to variations in water quality.

Montana↗

USGS2014

A GIS-based vulnerability assessment of brine contamination to aquatic resources from oil and gas development in eastern Sheridan County, Montana

Water (brine) co-produced with oil in the Williston Basin is some of the most saline in the nation. The Prairie Pothole Region (PPR), characterized by glacial sediments and numerous wetlands, covers the northern and eastern portion of the Williston Basin. Sheridan County, Montana, lies within the PPR and has a documented history of brine contamination. Surface water and shallow groundwater in the PPR are saline and sulfate dominated while the deeper brines are much more saline and chloride dominated. A Contamination Index (CI), defined as the ratio of chloride concentration to specific conductance in a water sample, was developed by the Montana Bureau of Mines and Geology to delineate the magnitude of brine contamination in Sheridan County. Values > 0.035 indicate contamination. Recently, the U.S. Geological Survey completed a county level geographic information system (GIS)-based vulnerability assessment of brine contamination to aquatic resources in the PPR of the Williston Basin based on the age and density of oil wells, number of wetlands, and stream length per county. To validate and better define this assessment, a similar approach was applied in eastern Sheridan County at a greater level of detail (the 2.59 km 2 Public Land Survey System section grid) and included surficial geology. Vulnerability assessment scores were calculated for the 780 modeled sections and these scores were divided into ten equal interval bins representing similar probabilities of contamination. Two surface water and two groundwater samples were collected from the section with the greatest acreage of Federal land in each bin. Nineteen of the forty water samples, and at least one water sample from seven of the ten selected sections, had CI values indicating contamination. Additionally, CI values generally increased with increasing vulnerability assessment score, with a stronger correlation for groundwater samples (R 2 = 0.78) than surface water samples (R 2 = 0.53).

Montana↗

USGS2014

A framework for assessing water and proppant use and flowback water extraction associated with development of continuous petroleum resources

The U.S. Geological Survey is developing approaches for the quantitative assessment of water and proppant involved with possible future production of continuous petroleum deposits. The assessment approach is an extension of existing U.S. Geological Survey petroleum-assessment methods, and it aims to provide objective information that helps decision makers understand the tradeoffs inherent in resource-development decisions. This fact sheet provides an overview of U.S. Geological Survey assessments for quantities of water and proppant required for drilling and hydraulic fracturing and for flowback water extracted with petroleum; the report also presents the form of the intended assessment output information.

Fact Sheet↗

USGS2014

Brine contamination to aquatic resources from oil and gas development in the Williston Basin, United States

The Williston Basin, which includes parts of Montana, North Dakota, and South Dakota in the United States and the provinces of Manitoba and Saskatchewan in Canada, has been a leading domestic oil and gas producing region for more than one-half a century. Currently, there are renewed efforts to develop oil and gas resources from deep geologic formations, spurred by advances in recovery technologies and economic incentives associated with the price of oil. Domestic oil and gas production has many economic benefits and provides a means for the United States to fulfill a part of domestic energy demands; however, environmental hazards can be associated with this type of energy production in the Williston Basin, particularly to aquatic resources (surface water and shallow groundwater) by extremely saline water, or brine, which is produced with oil and gas. The primary source of concern is the migration of brine from buried reserve pits that were used to store produced water during recovery operations; however, there also are considerable risks of brine release from pipeline failures, poor infrastructure construction, and flow-back water from hydraulic fracturing associated with modern oilfield operations. During 2008, a multidisciplinary (biology, geology, water) team of U.S. Geological Survey researchers was assembled to investigate potential energy production effects in the Williston Basin. Researchers from the U.S. Geological Survey participated in field tours and met with representatives from county, State, tribal, and Federal agencies to identify information needs and focus research objectives. Common questions from agency personnel, especially those from the U.S. Fish and Wildlife Service, were “are the brine plumes (plumes of brine-contaminated groundwater) from abandoned oil wells affecting wetlands on Waterfowl Production Areas and National Wildlife Refuges?” and “are newer wells related to Bakken and Three Forks development different than the older, abandoned wells (in terms of potential for affecting aquatic resources)?” Of special concern were the wetland habitats of the ecologically important Prairie Pothole Region, which overlays a part of the Williston Basin and is recognized for the production of a majority of North America’s migratory waterfowl. On the basis of the concerns raised by on-the-ground land managers, as well as findings from previous research, a comprehensive study was developed with the following goals: summarize existing information pertaining to oil and gas production and aquatic resources in the Williston Basin; assess brine plume migration from new and previously studied sites in the Prairie Pothole Region; perform a regional, spatial evaluation of oil and gas production activities and aquatic resources; assess the potential for brine contamination to wetlands and streams; and hold a decision analysis workshop with key stakeholders to discuss issues pertaining to oil and gas production and environmental effects and to identify information gaps and research needs. This report represents an initial, multidisciplinary evaluation of measured and potential environmental effects associated with oil and gas production in the Williston Basin and Prairie Pothole Region. Throughout this report there are reviews of current knowledge, and discussions relating to data gaps and research needs. On the basis of the information presented, future research needs include: regional geophysical and water-quality assessments to establish baselines for current conditions and estimate the extent of previous brine contamination, investigations into the direct effects of brine to biotic communities, and evaluations to identify the most effective techniques to mitigate brine contamination.

Montana, North Dakota↗

USGS2014

Delineation of brine contamination in and near the East Poplar oil field, Fort Peck Indian Reservation, northeastern Montana, 2004-09

The extent of brine contamination in the shallow aquifers in and near the East Poplar oil field is as much as 17.9 square miles and appears to be present throughout the entire saturated zone in contaminated areas. The brine contamination affects 15–37 billion gallons of groundwater. Brine contamination in the shallow aquifers east of the Poplar River generally moves to the southwest toward the river and then southward in the Poplar River valley. The likely source of brine contamination in the shallow aquifers is brine that is produced with crude oil in the East Poplar oil field study area. Brine contamination has not only affected the water quality from privately owned wells in and near the East Poplar oil field, but also the city of Poplar’s public water-supply wells. Three water-quality types characterize water in the shallow aquifers; a fourth water-quality type in the study area characterizes the brine. Type 1 is uncontaminated water that is suitable for most domestic purposes and typically contains sodium bicarbonate and sodium/magnesium sulfate as the dominant ions. Type 2 is moderately contaminated water that is suitable for some domestic purposes, but not used for drinking water, and typically contains sodium and chloride as the dominant ions. Type 3 is considerably contaminated water that is unsuitable for any domestic purpose and always contains sodium and chloride as the dominant ions. Type 3 quality of water in the shallow aquifers is similar to Type 4, which is the brine that is produced with crude oil. Electromagnetic apparent conductivity data were collected in the 106 square-mile area and used to determine extent of brine contamination. These data were collected and interpreted in conjunction with water-quality data collected through 2009 to delineate brine plumes in the shallow aquifers. Monitoring wells subsequently were drilled in some areas without existing water wells to confirm most of the delineated brine plumes; however, several possible plumes do not contain either existing water wells or monitoring wells. Analysis of groundwater samples from wells confirms the presence of 12.1 square miles of contamination, as much as 1.7 square miles of which is considerably contaminated (Type 3). Electromagnetic apparent conductivity data in areas with no wells delineate an additional 5.8 square miles of possible contamination, 2.1 square miles of which might be considerably contaminated (Type 3). Storage-tank facilities, oil wells, brine-injection wells, pipelines, and pits are likely sources of brine in the study area. It is not possible to identify discrete oil-related features as likely sources of brine plumes because several features commonly are co-located. During the latter half of the twentieth century, many brine plumes migrated beyond the immediate source area and likely mix together in modern and ancestral Poplar River valley subareas.

Montana↗

USGS2014

Hydrogeologic framework of the uppermost principal aquifer systems in the Williston and Powder River structural basins, United States and Canada

The glacial, lower Tertiary, and Upper Cretaceous aquifer systems in the Williston and Powder River structural basins within the United States and Canada are the uppermost principal aquifer systems and most accessible sources of groundwater for these energy-producing basins. The glacial aquifer system covers the northeastern part of the Williston structural basin. The lower Tertiary and Upper Cretaceous aquifer systems are present in about 91,300 square miles (mi 2 ) of the Williston structural basin and about 25,500 mi 2 of the Powder River structural basin. Directly under these aquifer systems are 800 to more than 3,000 feet (ft) of relatively impermeable marine shale that serves as a basal confining unit. The aquifer systems in the Williston structural basin have a shallow (less than 2,900 ft deep), wide, and generally symmetrical bowl shape. The aquifer systems in the Powder River structural basin have a very deep (as much as 8,500 ft deep), narrow, and asymmetrical shape. The Williston structural basin has been an important oil and natural gas producing region since the 1950s, and production has increased substantially since the mid-2000s due to improved drilling and hydraulic fracturing methods from deep formations, such as the Bakken and Three Forks Formations. These improved methods require considerable volumes of freshwater mostly from shallow aquifers or surface water. Coal, lignite, and coal-bed natural gas are additional sources of energy in both basins that can affect the quality and quantity of shallow aquifers through strip mining and groundwater depletion. In 2011, the U.S. Geological Survey initiated a regional study of the glacial, lower Tertiary, and Upper Cretaceous aquifer systems in the Williston and Powder River structural basins with the goal to quantify groundwater availability. This report, together with a companion report of the conceptual flow model, provides an improved understanding of the groundwater flow systems and a basis for a numerical, regional groundwater-flow model. This study combines the lithostratigraphic units of the glacial, lower Tertiary, and Upper Cretaceous aquifer systems in the United States and Canada into 7 regional hydrogeologic units—glacial deposits, 4 bedrock aquifers, and 2 bedrock confining units—using general hydraulic properties. The glacial deposits are composed of till and glacial outwash sands and gravels with areas of cobbles and boulders. The four bedrock aquifers are the upper Fort Union, lower Fort Union, lower Hell Creek, and Fox Hills aquifers and are contained primarily in sandstone layers. The two confining units are the middle Fort Union hydrogeologic unit (shale) and upper Hell Creek hydrogeologic unit (contains less sandstone than the underlying lower Hell Creek aquifer). Water from hydrogeologic units in these three aquifer systems is relatively fresh and potable, whereas withdrawals seldom occur from units below the basal confining unit because of great depths (greater than 800 ft) and poor water quality. Analysis of about 300 electric (resistivity) and lithologic logs in the Williston structural basin and numerous existing publications for the Powder River structural basin were used to develop a three-dimensional hydrogeologic framework for both basins. Interpolated thicknesses of the glacial deposits, the lower Tertiary aquifer system, and the Upper Cretaceous aquifer system in the Williston structural basin are less than about 750; 2,250; and 1,050 ft, respectively. Interpolated thicknesses of the lower Tertiary aquifer system and the Upper Cretaceous aquifer system in the Powder River structural basin are less than about 7,180 and 5,070 ft, respectively. Interpolated horizontal hydraulic conductivity values for the Williston structural basin were as much as 25 feet per day (ft/d) in the glacial deposits and had smaller ranges in the lower Tertiary aquifer system (0.01–9.8 ft/d) and in the Upper Cretaceous aquifer system (0.06–5.5 ft/d). In the Powder River structural basin, the lower Tertiary aquifer system had a greater range of interpolated horizontal hydraulic conductivity values (0.10–11 ft/d) than the Upper Cretaceous aquifer system (0.02–5.7 ft/d). Transmissivity is greatest in the gravel zones of the glacial deposits (2,120 feet squared per day) and generally decreases with depth into the bedrock units. Regionally, water in the lower Tertiary and Upper Cretaceous aquifer systems flows in a northerly or northeasterly direction from the Powder River structural basin to the Williston structural basin. Groundwater flow in the Williston structural basin generally is easterly or northeasterly. Flow in the uppermost hydrogeologic units generally is more local and controlled by topography where unglaciated in the Williston structural basin than is flow in the glaciated part and in underlying aquifers. Groundwater flow in the Powder River structural basin generally is northerly with local variations greatest in the uppermost aquifers. Groundwater is confined, and flow is regional in the underlying aquifers.

Powder River Basin;Williston Basin↗