Source: https://semanticommunity.info/Data_Science/Data_Science_for_EPA_Big_Data_Analytics/Data_Science_for_USGS_Produced_Waters
Timestamp: 2019-04-23 10:30:10+00:00

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The goal is to do data science on the USGS Produced Waters data set and explore integration of it with the EPA Fracturing Data in preparation for a Hackathon by a Hacking Community and a Federal Big Data Working Group Meetup in 2016.
I mined the USGS Produced Waters Web Pages for Data (67 MB) and Documentation (PDF converted to Word and repurposed to this MindTouch Wiki) and created a Knowledge Base in MindTouch and a Spreadsheet in Excel for import into Spotfire. After exploring the USGS Produced Waters Data and Documentation by itself then I will import those data into the EPA Fracturing Data Spotfire file and work on the integration problem.
I tried to quickly recreate the three USGS Produced Waters visualizations below (Box Plot of TDS by Basin, TDS by AgeCode, and Map by Basin with Colors.
Develop interactive visualizations and stories about the water and chemicals used in hydraulic fracturing. Integrate the USGS Produced Waters Geochemical Database with other datasets related to hydraulic fracturing, like FracFocus, to visualize and explain the lifecycle of hydraulic fracturing water and chemicals.
The U.S. Geological Survey (USGS) Energy Resources Program (ERP) conducts research and develops products that characterize the complex energy resource lifecycle of occurrence, formation processes, extraction methods, and use. Understanding the energy resource lifecycle can influence and be influenced by landscape, hydrology, climate, ecosystems, and human health. Development and production of energy resources require and produce significant quantities of water and chemicals that can affect environmental and human health. The USGS has developed a product called the Produced Waters Geochemical Database, which is a compilation of 25 individual databases, publications, and reports containing geochemical and other information about produced waters and other deep formation waters of the United States. The Groundwater Protection Council developed the FracFocus website to provide the public with voluntary disclosure reports submitted by oil and gas drilling operators about the chemicals they used in hydraulic fracturing operations across the United States.
In an ideal world, prior to developing unconventional oil and gas accumulations, we would first have a sample of pre-existing formation water in a given reservoir. We would also know the composition of the fracking fluid, not only the chemical additives listed in FracFocus, but also the full composition of the injected water, which may itself be a produced water from another reservoir. Then, we would have a series of flowback waters from the well that represent a mixture of injected water, formation water, and additives, including any chemical reactions that happened underground. In reality, we usually only have that last flowback mixture sample. FracFocus provides information about additives and water volumes, but the two major unknowns are the initial formation water composition and the composition of the injected fluid. Sometimes the composition of the fluid is disclosed from some service companies, like Schlumberger’s OpenFRAC Fully Disclosed Hydraulic Fracturing Fluids, but these compositions can be somewhat vague.
We would like your help with generating interactive visualizations related to hydraulic fracturing by integrating the Produced Waters Geochemical Database with other datasets like FracFocus to address the following questions: Where in the U.S. have produced waters and chemicals been injected into wells? How much water was actually used in the wells that have already been fracked? How can integrating multiple datasets help us begin visualizing the lifecycle of hydraulic fracturing water and chemicals?
You can produce proof-of-concept visualizations or interactive stories about the lifecycle of hydraulic fracturing water and chemicals. You can also provide recommendations on how USGS datasets and other hydraulic fracturing datasets could be better organized, architected, and presented to make it easier for you to produce visualizations and to tell better stories about hydraulic fracturing.
Any output resulting from the challenge are intended to be used by the USGS Energy Resources Program for research and potentially integrated with other online products at http://energy.usgs.gov.
Significant quantities of water are produced in the extraction of hydrocarbon energy resources (currently estimated at ~14 billion bbl/yr across the United States [1 bbl=42 gallons]). An additional volume of hydraulic fracturing (“fracing”) fluid, used to increase permeability, porosity, and hydrocarbon yield of reservoir rocks, is recovered at the end of the process (flowback fluids). Water is also generated from scrubbers in power plants, dewatering and extracting uranium resources, carbon sequestration, and development of unconventional energy sources. Although derived from a variety of different sources, these all represent sources of produced waters in that they are extracted in the process of trying to develop, extract, or dispose of energy-related products.
Photo: Sampling produced water from an oil well in northern Louisiana.
Produced waters typically exhibit significant variations in salinity, sodicity, trace element composition, and organic geochemistry resulting from differences in environmental and geologic conditions. Some of these waters contain relatively high salinity values, sometimes greater than seawater, while others are potable. However, continued concerns over diminishing water resources and expanding needs for next generation energy sources have lead to the characterization of produced waters as possible resources.
Assessing Impacts of Coalbed Methane Produced Waters – Coalbed methane is produced by de-watering coal beds, and has become an increasingly important source of energy in the United States. The USGS is studying the environmental impacts from use and disposal of related produced waters.
Characterization and Sources of Appalachian Basin Produced Waters – Despite a long history of oil and gas development in the eastern United States, sparse compositional dataexist for produced waters. This drive, along with renewed interest in Marcellus Shale gas accumulations, is sparking research on the source and chemistry of current and future produced waters from the Appalachian Basin.
Water Balances for Energy Resource Production – USGS scientists are developing water budget methods for understanding inputs and outputs from regional oil and gas resources.
Disclaimer: The data you have secured from the U.S. Geological Survey National Produced Waters Geochemical Database v2.1 are provisional and subject to revision. The data are released on the condition that neither the USGS nor the United States Government may be held liable for any damages resulting from its authorized or unauthorized use.
During hydrocarbon exploration and extraction, water is typically co-produced from the same subsurface geologic formations. Understanding the composition of these produced waters is important to help investigate the regional hydrogeology, the source of the water and hydrocarbons, the necessary water treatment and disposal plans, potential economic benefits of commodities in the fluids, and the safety of potential sources of drinking or agricultural water. Additionally, during geothermal development or exploration, other deep formation waters are brought to the surface and may be sampled. This U.S. Geological Survey (USGS) Produced Waters Geochemical Database, which contains geochemical and other information for produced waters and other deep formation waters of the United States, is a provisional, updated version of the 2002 USGS Produced Waters Database. In addition to the major element data presented in the original, the new database contains trace elements, isotopes, and time-series data, as well as nearly 100,000 new samples with greater spatial coverage and from both conventional and unconventional well types, including geothermal. The database is a compilation of 25 individual databases, publications, or reports. The database was created in a manner to facilitate addition of new data and fix any compilation errors, and is expected to be updated with new data as provided and needed.
Coalbed methane (CBM), also called coalbed natural gas, currently contributes ~10% to U.S. natural gas production, but generates more water than traditional gas sources. CBM is generated by de-watering coal, and thus reducing pressure within the coal bed, allowing adsorbed volatile compounds, such as methane, to be transported out of the subsurface and captured (fig. 1).
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-HCO3type 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.
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.
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.
Considerable work has been done to characterize the inorganic, major element chemistry of produced waters from western basins of the United States, but equivalent data for the Appalachian Basin are scarce, despite significant oil and gas production. Across the Appalachian Basin, salinities of produced waters range from fresh to more than 350,000 mg/L TDS (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).
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.
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).
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.
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.
New technologies have expanded domestic oil and gas production to include low-permeability formations once considered to be inaccessible, including the Bakken Formation in northern Montana and North Dakota, the Barnett Shale in Texas, and the Marcellus Shale in the Appalachian states (fig. 1). Hydrocarbon production from these formations requires considerable quantities of fresh water (surface and/or groundwater) to 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.
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 data you have secured from the U.S. Geological Survey (USGS) National Produced Waters Geochemical Database v2.1 are provisional and subject to revision. The data are released on the condition that neither the USGS nor the United States Government may be held liable for any damages resulting from its authorized or unauthorized use.
Although the data have been processed on computer systems at the USGS, U.S. Department of the Interior, no warranty, expressed or implied, is made by the Geological Survey regarding the utility of the data on any other system, nor shall the act of distribution constitute any such warranty. No responsibility is assumed by the USGS in the use of these data.
The information in the USGS National Produced Waters Geochemical Database v2.1 should be used with careful consideration of its limitations. The database is considered sufficiently accurate to provide an indication of tendencies in water composition from geographically and geologically defined areas. It is not appropriate for depiction of modern produced water compositions or examination of trends on small scales. The USGS makes no warranty regarding the accuracy or completeness of information presented in this database. Specific limitations of the database should be considered. Much of the information in the database cannot be independently verified. Methods of collection, sample preservation, analysis, assignment of geologic units and record keeping were not rigorous or standardized. Because of these uncertainties, users are advised to check data for inconsistencies, outliers, and obviously flawed information. Methods of well construction, sample collection and chemical analysis have changed over time. The distribution and relative amount of water produced within a province and among geologic units may not be fully represented by the samples in the database. No sampling was planned to accurately depict the aggregate water composition of any area whether it be province, state, county or field. The geologic unit nomenclature developed for petroleum production may have changed over time. Data from a province collected 30 years ago may not resemble current production. The composition of produced water within a province, field or even well may change in time as a result of water flooding, recompletion in other intervals, and workovers. Water samples are commonly collected when a well has production problems or during the initial development of a well. Although criteria were applied to remove the obviously contaminated samples, the culling of unrepresentative data is considered incomplete. Most obvious redundant entries were removed from this database, many of the records represent multiple samples of the same well. Therefore aggregate statistics may be weighted by relatively few wells.
During hydrocarbon exploration and extraction, water is typically co-produced from the same subsurface geologic formations. Understanding the composition of these produced waters is important to help investigate the regional hydrogeology, the source of the water and hydrocarbons, the necessary water treatment and disposal plans, potential economic benefits of commodities in the fluids, and the safety of potential sources of drinking or agricultural water. Additionally, during geothermal development or exploration, other deep formation waters are brought to the surface and may be sampled. This U.S. Geological Survey (USGS) Produced Waters Geochemical Database, which contains geochemical and other information for 161,915 produced water and other deep formation water samples of the United States, is a provisional, updated version of the 2002 USGS Produced Waters Database (Breit and others, 2002). In addition to the major element data presented in the original, the new database contains trace elements, isotopes, and time-series data, as well as nearly 100,000 new samples with greater spatial coverage and from both conventional and unconventional well types, including geothermal. The database is a compilation of 25 individual databases, publications, or reports. The database was created in a manner to facilitate addition of new data and fix any compilation errors, and is expected to be updated with new data as provided and needed. Table 1 shows the abbreviated names (IDDB) of each input database, the number of samples from each, and its reference. Table 2 defines the 241 variables contained in the database and their descriptions. The database variables are organized first with identification and location information, followed by well descriptions, dates, rock properties, physical properties of the water, and then chemistry. The chemistry is organized alphabetically by elemental symbol, each element is followed by any associated compounds (e.g. H2S is found after S). After Zr, molecules containing carbon follow, including measures of alkalinity, dissolved organic carbon (DOC), and hydrocarbons. Isotopic data are found at the end of the dataset.
-1 = Trace, minor, present, or a qualitative description of some amount.
1 Disclaimer: Use of brand or trade names are for descriptive purpose and do not imply endorsement by the U.S. Government.
Negative values are used for concentration data codes because all true concentrations are positive and therefore will not overlap with the codes. Negative values can easily be removed by the user when manipulating data. Furthermore, dates are formatted into a consistent date form and extra variables are removed. Units for all variables other than the major and minor ions are defined in table 2. The major and minor ions are generally reported in units of milligrams per liter (mg/L) or parts per million (ppm) on a mass basis, also defined as milligrams per kilogram (mg/kg). If the ion concentrations were originally reported in mg/L, a “1” is added to the MGL variable column of the database. If the ion concentrations were originally reported in ppm, a “1” is added to the PPM variable column of the database. The user of this database must be careful to examine these units when using the data, and can convert between the two using measurements or estimates of brine density.
Each individual input database is then appended to the template using a global Stata routine. The database is further standardized here with internally consistent 14-digit American Petroleum Institute well identification numbers (API), state names (STATE), and one of seven well type (WELLTYPE) designations (Conventional Hydrocarbon, Shale Gas, Tight Oil, Tight Gas, Coal Bed Methane, Geothermal, and Groundwater). Future standardization will be performed on other important variables such as FORMATION.
Duplicates were found within single datasets and between them. Duplicate culling is done using API well numbers and the concentrations of variables with large numbers of significant figures because it is highly unlikely that even samples taken from the same well at the same time will have the exact same values for three or more elements. API, Calcium (Ca), Chloride (Cl), and bicarbonate (HCO3) concentrations are used to search for duplicates. Care was taken to avoid false duplicates (for example, where all three ions had the code of “-4” or all three ions had null data). There were 92,153 unique observations according to these duplicate search criteria, 8,539 groups of 2 observations (duplicates), 1,179 groups of 3 observations (triplicates), 157 groups of 4 observations, 13 groups of 5 observations, 5 groups of 6 observations, and 2 groups of 7 observations (table 3). After locating these duplicates, a second check was often performed using Mg, Na, or sample collection date to determine if they were true duplicates. The duplicate observation retained was generally the one in the database that contained more information. The order of which database had primacy follows the order of table 1.
Quality control of the dataset can be performed by culling based on geochemical criteria. In this version 2.1 of the provisional database, the data that fall outside of the bounds of the following criteria are flagged, rather than culled. There are six temporary columns in the database that represent the failure of specific culling criteria, based on those published in Hitchon and Brulotte (1994). An “X” is placed in the columns shown in table 2 where the sample falls outside of the pH range of 4.5 – 10.5, where Mg > Ca, K > Cl, K > 5xNa, and the charge balance is greater than 5%.
Version 2.1 corrects errors found in version 2.0 of the database. Incorrect LAT, LONG, or STATE variables were updated based on API or other well information. Chemical and well data in incorrect columns were placed in the correct columns. Unit problems were fixed for chemistry and specific gravity data. Alkalinity data were put into the correct columns based on the method of measurement. Certain variables not given in the original input datasets, including WELLTYPE and age information were determined based on well and formation data. Various other errors noted by users were corrected by referring back to the original source of the data. No new datasets were added except IDDB = “WILLISTON,” which is a compilation of the EASTPOPLAR and BAKKEN entries from version 2.0 of the database along with unpublished data (Thamke, 2014, written communication).
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