Geology topics

Madalyn S. Blondes

Publications and source records attributed to Madalyn S. Blondes.

At least 19 recordsLinked to original sources

USGS2025

U.S. Geological Survey research and assessments supporting carbon dioxide removal

Both carbon capture and storage (CCS) and carbon dioxide removal (CDR) are methods to limit future global temperature rise and ocean acidification. CCS sequesters (stores) carbon dioxide (CO2) captured from industrial sources thereby preventing the CO2 from reaching the atmosphere. The captured CO2 is injected into underground geologic reservoirs or is converted into stable industrial products. CDR enhances natural processes or uses technical approaches to remove excess CO2 from the atmosphere. Carbon dioxide is sequestered in natural sinks such as vegetation and soil, or injected into underground reservoirs or converted into durable products. The U.S. Geological Survey (USGS) conducts research and resource assessments that support biologic and geologic CDR approaches. This report will review some of the ongoing USGS CDR research and assessment efforts.

Conference Paper↗

USGS2024

Ion exchange processes for CO2 mineralization using industrial waste streams: Pilot plant demonstration and life cycle assessment

An attractive technique for removing CO 2 from the environment is sequestration within stable carbonate solids (e. g., calcite). However, continuous addition of alkalinity is required to achieve favorable conditions for carbonate precipitation (pH>8) from aqueous streams containing dissolved CO 2 (pH<4.5) and Ca 2+ ions. In this study, a pH-swing process using ion exchange was demonstrated to process 300 L of produced water brine per day for CO 2 mineralization. Proton titration capacities were quantified for aqueous streams in equilibrium with gas streams at various concentrations of CO 2 (pCO 2 =0.03–0.20 atm) and at various flow rates (0.5–2.0 L min −1 ). Energy intensities for the process were determined to be between 30 and 65 kWh per tonne of CO 2 sequestered depending on the composition of the brine stream. A life cycle assessment was performed to analyze the net carbon emissions of the technology which indicated a net CO 2 reduction for pCO 2 ≥0.12 atm (−0.06–−0.39 kg CO 2 e per kg precipitated CaCO 3 ) utilizing calcium-rich brines. The results from this study indicate the ion exchange process can be used as a scalable method to provide alkalinity necessary for the capture and storage of CO 2 in Ca-rich waste streams.

Chemistry Select↗

USGS2024

Utica/Point Pleasant brine isotopic compositions (δ7Li, δ11B, δ138Ba) elucidate mechanisms of lithium enrichment in the Appalachian Basin

Global Li production will require a ~500 % increase to meet 2050 projected energy storage demands. One potential source is oil and gas wastewater (i.e., produced water or brine), which naturally has high total dissolved solids (TDS) concentrations, that can also be enriched in Li (>100 mg/L). Understanding the sources and mechanisms responsible for high naturally-occurring Li concentrations can aid in efficient targeting of these brines. The isotopic composition (δ 7 Li, δ 11 B, δ 138 Ba) of produced water and core samples from the Utica Shale and Point Pleasant Formation (UPP) in the Appalachian Basin, USA indicates that depth-dependent thermal maturity and water-rock interaction, including diagenetic clay mineral transformations, likely control Li concentrations. A survey of Li content in produced waters throughout the USA indicates that Appalachian Basin brines from the Marcellus Shale to the UPP have the potential for economic resource recovery.

Maryland, Ohio, Pennsylvania, West Virginia↗

USGS2024

Produced water geochemistry from hydraulically stimulated Niobrara Formation petroleum wells: Origin of salinity and temporal perspectives on treatment and reuse

Produced water (i.e., a mixture of returned injection fluids and geologic formation brines) represents the largest volumetric waste stream associated with petroleum production in the United States. As such, produced water has been the focus of intense study with emphasis on understanding the geologic origin of the fluids, environmental impacts of unintended or intentional release, disposal concerns, and their commodity (e.g., lithium) potential. However, produced water geochemistry from many active petroleum plays remain poorly constrained leading to knowledge gaps associated with the origin of brine salinity and parameters (e.g., radium levels) that can impact treatment, disposal, and possible reuse. Here we evaluate the major ion geochemistry, radium concentrations, and stable water isotope composition of ~120 produced water samples collected from 17 producing unconventional petroleum wells in Weld County, Colorado from the Late Cretaceous Niobrara Formation. This sample set encompasses eight produced water time series from four new wells across production days 0 to ~365 and from four established wells across production days ~1000 to ~1700. Additionally, produced water from nine other established Niobrara Formation wells were sampled at discrete time points ranging from day 458 to day 2256, as well as hydraulic fracturing input fluids. These results expand the available Niobrara Formation produced water geochemical data, previously limited to few wells sampled within the first year of production, allowing for the heterogeneity of major ions and radium to be evaluated. Furthermore, we explore the geochemical relationships between major ion ratios and stable water isotope composition to understand the origin of salinity in Niobrara Formation brines from the Denver-Julesburg Basin. These findings are discussed with perspective toward potential treatment and reuse of Niobrara produced water prior to disposal.

Colorado, Nebraska, Wyoming↗

USGS2024

Evaluation of the lithium resource in the Smackover Formation brines of southern Arkansas using machine learning

Global demand for lithium, the primary component of lithium-ion batteries, greatly exceeds known supplies, and this imbalance is expected to increase as the world transitions away from fossil fuel energy sources. High concentrations of lithium in brines have been observed in the Smackover Formation in southern Arkansas (>400 milligrams per liter). We used published and newly collected brine lithium concentration data to train a random forest machine-learning model using geologic, geochemical, and temperature explanatory variables and create a map of predicted lithium concentrations in Smackover Formation brines across southern Arkansas. Using these predicted lithium maps with reservoir parameters and geologic information, we calculated that there are 5.1 to 19 million tons of lithium in Smackover Formation brines in southern Arkansas, which represents 35 to 136% of the current US lithium resource estimate. Based on these calculations, in 2022, 5000 tons of dissolved lithium were brought to the surface within brines as waste streams of the oil, gas, and bromine industries.

Arkansas↗

USGS2023

Geologic carbon management options for the North Atlantic-Appalachian Region

Introduction The U.S. Geological Survey (USGS) North Atlantic-Appalachian Region is developing the regionwide capacity to provide timely science support for decision-makers attempting to enhance carbon removal, sequestration, and emissions mitigation to meet national atmospheric carbon reduction goals. The U.S. Environmental Protection Agency (EPA) reported that in 2021, the fourteen States and the District of Columbia in the northeastern region account about for approximately 18 percent of the total national greenhouse gas (GHG) emissions. This Fact Sheet provides a summary of USGS science information and ongoing and new investigations or data-collection programs that may help the northeastern region decrease the release of carbon-containing GHG to the atmosphere.

Connecticut, Delaware, Maine, Maryland, Massachuse↗

USGS2022

National assessment of carbon dioxide enhanced oil recovery and associated carbon dioxide retention resources — Results

In 2020, the U.S. Geological Survey (USGS) completed a probabilistic assessment of the volume of technically recoverable oil resources available if current carbon dioxide enhanced oil recovery (CO 2 -EOR) technologies were applied to amenable oil reservoirs underlying the onshore and State waters areas of the conterminous United States. The assessment also includes estimates of the mass of CO 2 that could be stored (retained) as a result of CO 2 -EOR activities. The USGS assessment team evaluated more than 3,500 oil reservoirs that were miscible to injected CO 2 . The assessed reservoirs are in 185 previously defined USGS plays in 33 petroleum provinces of 7 national regions. The assessment team estimated that the technically recoverable oil associated with CO 2 -EOR ranges from approximately 25,000 million barrels (MMbbl) at the P 5 percentile to as much as 32,000 MMbbl at the P 95 percentile, with a mean of 29,000 MMbbl. The associated CO 2 retention ranges from approximately 7,400 million metric tons (Mt) at the P 5 percentile to as much as 9,500 Mt at the P 95 percentile, with a mean of 8,400 Mt. The West Texas and Eastern New Mexico region and the Gulf Coast region together contain 60 percent of the mean assessed CO 2 -EOR oil potential and 61 percent of the mean assessed CO 2 retention. Other regions with significant resource potential include the Midcontinent region and Rocky Mountains and Northern Great Plains region.

Continental United States↗

USGS2022

National assessment of carbon dioxide enhanced oil recovery and associated carbon dioxide retention resources — Summary

Introduction In 2020, the U.S. Geological Survey (USGS) completed a probabilistic assessment of the volume of technically recoverable oil resources that might be produced by using current carbon dioxide enhanced oil recovery (CO 2 -EOR) technologies in amenable conventional oil reservoirs underlying the onshore and State waters areas of the conterminous United States. The assessment also includes estimates of the mass of CO 2 that could be stored (retained) in the assessed oil reservoirs following the application of the CO 2 -EOR process. The USGS assessment team evaluated more than 3,500 oil reservoirs that were miscible to injected CO 2 . The assessed reservoirs are in 185 previously defined USGS plays in 33 petroleum provinces of 7 national regions. The team estimated that the total technically recoverable oil resulting from the application of the CO 2 -EOR process ranges from approximately 25,000 million barrels (MMbbl) at the P 5 percentile to as much as 32,000 MMbbl at the P 95 percentile, with a mean of 29,000 MMbbl. The associated CO 2 retention ranges from approximately 7,400 million metric tons (Mt) at the P 5 percentile to as much as 9,500 Mt at the P 95 percentile, with a mean of 8,400 Mt. The results are summarized in this fact sheet and are provided in more detail in the companion data release and circular. The West Texas and Eastern New Mexico region (primarily its Permian Basin) and the Gulf Coast region together contain 60 percent of the mean assessed CO 2 -EOR oil potential and 61 percent of the mean assessed CO 2 retention. Other regions with significant resource potential include the Midcontinent region and the Rocky Mountains and Northern Great Plains region.

Continental United States↗

USGS2022

Dissolved organic matter within oil and gas associated wastewaters from U.S. unconventional petroleum plays: Comparisons and consequences for disposal and reuse

Wastewater generated during petroleum extraction (produced water) may contain high concentrations of dissolved organics due to their intimate association with organic-rich source rocks, expelled petroleum, and organic additives to fluids used for hydraulic fracturing of unconventional (e.g., shale) reservoirs. Dissolved organic matter (DOM) within produced water represents a challenge for treatment prior to beneficial reuse. High salinities characteristic of produced water, often 10× greater than seawater, coupled to the complex DOM ensemble create analytical obstacles with typical methods. Excitation-emission matrix spectroscopy (EEMS) can rapidly characterize the fluorescent component of DOM with little impact from matrix effects. We applied EEMS to evaluate DOM composition in 18 produced water samples from six North American unconventional petroleum plays. Represented reservoirs include the Eagle Ford Shale (Gulf Coast Basin), Wolfcamp/Cline Shales (Permian Basin), Marcellus Shale and Utica/Point Pleasant (Appalachian Basin), Niobrara Chalk (Denver-Julesburg Basin), and the Bakken Formation (Williston Basin). Results indicate that the relative chromophoric DOM composition in unconventional produced water may distinguish different lithologies, thermal maturity of resource types (e.g., heavy oil vs. dry gas), and fracturing fluid compositions, but is generally insensitive to salinity and DOM concentration. These results are discussed with perspective toward DOM influence on geochemical processes and the potential for targeted organic compound treatment for the reuse of produced water.

Colorado, Montana, Nebraska, New York, North Dakot↗

USGS2022

Assessment of carbon dioxide enhanced oil recovery and associated carbon dioxide retention resources of the United States

In 2020, the U.S. Geological Survey (USGS) completed a probabilistic assessment of the volume of technically recoverable oil resources that could be produced using current carbon dioxide enhanced oil recovery (CO2-EOR) technologies in amenable conventional oil reservoirs underlying onshore and State-owned offshore waters (herein after, onshore and State waters areas) of the conterminous United States. Our assessment also includes estimates of the mass of CO2 that could be stored (retained) in the assessed oil reservoirs following the application of the CO2-EOR process. The USGS assessment team evaluated more than 3,500 oil reservoirs that were amenable to miscible CO2 injection. The assessed reservoirs are located in 185 plays previously defined by a USGS National Oil and Gas Assessment in 33 petroleum provinces of seven national regions. The team estimated that the total technically recoverable oil resulting from the application of the CO2-EOR process ranges from approximately 25,000 million barrels (MMbbl) at the P5 probability percentile to as much as 32,000 MMbbl at the P95 probability percentile, with a mean of 29,000 MMbbl. The associated CO2 retention ranges from approximately 7,400 million metric tons (Mt) at the P5 percentile to as much as 9,500 Mt at the P95 percentile, with a mean of 8,400 Mt.

conterminous United States↗

USGS2021

Machine learning can assign geologic basin to produced water samples using major ion geochemistry

Understanding the geochemistry of waters produced during petroleum extraction is essential to informing the best treatment and reuse options, which can potentially be optimized for a given geologic basin. Here, we used the US Geological Survey’s National Produced Waters Geochemical Database (PWGD) to determine if major ion chemistry could be used to classify accurately a produced water sample to a given geologic basin based on similarities to a given training dataset. Two datasets were derived from the PWGD: one with seven features but more samples (PWGD7), and another with nine features but fewer samples (PWGD9). The seven-feature dataset, prior to randomly generating a training and testing (i.e., validation) dataset, had 58,541 samples, 20 basins, and was classified based on total dissolved solids (TDS), bicarbonate (HCO 3 ), Ca, Na, Cl, Mg, and sulfate (SO 4 ). The nine-feature dataset, prior to randomly splitting into a training and testing (i.e., validation) dataset, contained 33,271 samples, 19 basins, and was classified based on TDS, HCO 3 , Ca, Na, Cl, Mg, SO 4 , pH, and specific gravity. Three supervised machine learning algorithms—Random Forest, k-Nearest Neighbors, and Naïve Bayes—were used to develop multi-class classification models to predict a basin of origin for produced waters using major ion chemistry. After training, the models were tested on three different datasets: Validation7, Validation9, and one based on data absent from the PWGD. Prediction accuracies across the models ranged from 23.5 to 73.5% when tested on the two PWGD-based datasets. A model using the Random Forest algorithm predicted most accurately compared to all other models tested. The models generally predicted basin of origin more accurately on the PWGD7-based dataset than on the PWGD9-based dataset. An additional dataset, which contained data not in the PWGD, was used to test the most accurate model; results suggest that some basins may lack geochemical diversity or may not be well described, while others may be geochemically diverse or are well described. A compelling result of this work is that a produced water basin of origin can be determined using major ions alone and, therefore, deep basinal fluid compositions may not be as variable within a given basin as previously thought. Applications include predicting the geochemistry of produced fluid prior to drilling at different intervals and assigning historical produced water data to a producing basin.

Natural Resources Research↗

USGS2021

Potential Pb+2 mobilization, transport, and sequestration in shallow aquifers impacted by multiphase CO2 leakage: A natural analogue study from the Virgin River Basin in Southwest Utah

Geological carbon sequestration (GCS) is necessary to help meet emissions reduction goals, but groundwater contamination may occur if CO 2 and/or brine were to leak out of deep storage formations into the shallow subsurface. For this study, a natural analogue was investigated: in the Virgin River Basin of southwest Utah, water with moderate salinity and high CO 2 concentrations is leaking upward into shallow aquifers that contain heavy metal-bearing concretions. The aquifer system is comprised of the Navajo and Kayenta formations, which are pervasive across southern Utah and have been considered as a potential GCS injection unit where they are sufficiently deep. Numerical models of the site were constructed based on measured water chemistry and head distributions from previous studies. Simulations were used to improve understanding of the rate and distribution of the upwelling flow into the aquifers, and to assess the reactive transport processes that may occur if the upwelling fluids were to interact with a zone of iron oxide and other heavy metals, representing the concretions that are common in the area. Various mineralogies were tested, including one in which Pb +2 was adsorbed onto ferrihydrite, and another in which it was bound within a solid mixture of litharge (PbO) and hematite (Fe 2 O 3 ). Results indicate that metal mobilization depends strongly on the source zone composition and that Pb +2 transport can be naturally attenuated by gas phase formation and carbonate mineral precipitation. These findings could be used to improve risk assessment and mitigation strategies at geological carbon sequestration sites.

Utah↗

USGS2020

Utica shale play oil and gas brines: Geochemistry and factors influencing wastewater management

The Utica and Marcellus Shale Plays in the Appalachian Basin are the fourth and first largest natural gas producing plays in the United States, respectively. Hydrocarbon production generates large volumes of brine (“produced water”) that must be disposed of, treated, or reused. Though Marcellus brines have been studied extensively, there are few studies from the Utica Shale Play. This study presents new brine chemical analyses from 16 Utica Shale Play wells in Ohio and Pennsylvania. Results from Na–Cl–Br systematics and stable and radiogenic isotopes suggest that the Utica Shale Play brines are likely residual pore water concentrated beyond halite saturation during the formation of the Ordovician Beekmantown evaporative sequence. The narrow range of chemistry for the Utica Shale Play produced waters (e.g., total dissolved solids = 214–283 g/L) over both time and space implies a consistent composition for disposal and reuse planning. The amount of salt produced annually from the Utica Shale Play is equivalent to 3.4% of the annual U.S. halite production. Utica Shale Play brines have radium activities 580 times the EPA maximum contaminant level and are supersaturated with respect to barite, indicating the potential for surface and aqueous radium hazards if not properly disposed of.

Kentucky, Maryland, New York, Ohio, Pennsylvania, ↗

USGS2020

Four-dimensional thermal evolution of the East African Orogen: Accessory phase petrochronology of crustal profiles through the Tanzanian Craton and Mozambique Belt, northeastern Tanzania

U–Pb petrochronology of deep crustal xenoliths and outcrops across northeastern Tanzania track the thermal evolution of the Mozambique Belt and Tanzanian Craton following the Neoproterozoic East African Orogeny (EAO) and subsequent Neogene rifting. At the craton margin, the upper–middle crust record thermal quiescence since the Archean (2.8–2.5 Ga zircon, rutile, and apatite in granite and amphibolite xenoliths). The lower crust of the craton documents thermal pulses associated with Neoarchean ultra-high temperature metamorphism (ca. 2.64 Ga, > 900 °C zircon), the EAO (600–500 Ma rutile), and fluid influx during rifting (< 5 Ma apatite). Rutile in garnet granulite xenoliths exhibits partial Pb loss related to slow cooling of the lower crust after the EAO and suggests residence at 500–600 °C prior to entrainment. In contrast to the craton, the entire crust of the Mozambique Belt underwent differential cooling following the EAO. Both the upper and middle crust record metamorphism from 640 to 560 Ma (zircon, monazite, and titanite) and rapid exhumation at 510–440 Ma (rutile and apatite). Lower crustal xenoliths contain Archean zircon, but near-zero age rutile and apatite, indicating residence > 650 °C (above Pb closure of rutile and apatite) at the time of eruption. Zoned titanite records growth during cooling of the lower crust at 550 Ma, followed by fluid influx during slow cooling and exhumation (0.1–1 °C/Myr after 450 Ma). Permissible lower-crustal temperatures for the craton and orogen suggest variable mantle heat flow through the crust and reflect differences in mantle lithosphere thickness rather than advective heating from rifting.

Contributions to Mineralogy and Petrology↗

USGS2020

Repetitive sampling and control threshold improve 16S rRNA results from produced waters associated with hydraulically fractured shales

Sequencing microbial DNA from deep subsurface environments is complicated by a number of issues ranging from contamination to non-reproducible results. Many samples obtained from these environments - which are of great interest due to the potential to stimulate microbial methane generation - contain low biomass. Therefore, samples from these environments are difficult to study as sequencing results can be easily impacted by contamination. In this case, the low amount of sample biomass may be effectively swamped by the contaminating DNA and generate misleading results. Additionally, performing field work in these environments can be difficult, as researchers generally have limited access to and time on site. Therefore, optimizing a sampling plan to produce the best results while collecting the greatest number of samples over a short period of time is ideal. This study aimed to recommend an adequate sampling plan for field researchers obtaining microbial biomass for 16S rRNA gene sequencing, applicable specifically to oil and gas-producing environments. Forty-nine different samples were collected by filtering specific volumes of produced water from a hydraulically fractured well producing from the Niobrara Shale. Water was collected in two different sampling events 24 hours apart. Four to five samples were collected from 11 specific volumes. These samples along with eight different blanks were submitted for analysis. DNA was extracted from each sample, and quantitative polymerase chain reaction (qPCR) and 16S rRNA Illumina MiSeq gene sequencing were performed to determine relative concentrations of biomass and microbial community composition, respectively. The qPCR results varied across sampled volumes, while no discernible trend correlated contamination to volume of water filtered. This suggests that collecting a larger volume of sample may not result in larger biomass concentrations or better representation of a sampled environment. Researchers could prioritize collecting many low volume samples over few high-volume samples. Our results suggest that there also may be variability in the concentration of microbial communities present in produced waters over short (i.e., hours) time scales, which warrants further investigation. Submission of multiple blanks is also vital to determining how contamination or low biomass effects may influence a sample set collected from an unknown environment.

Montana, Wyoming, Colorado, New Mexico, Texas, Okl↗

USGS2020

Modeling geologic sequestration of carbon dioxide in a deep saline carbonate reservoir with TOUGH2–ChemPlugin, a new tool for reactive transport modeling

This paper outlines the development and demonstration of a new tool, TOUGH2–ChemPlugin (T2CPI) for predicting rock–water–CO 2 interaction following injection of supercritical CO 2 into a heterogeneous carbonate system. Specifically, modeling capabilities of TOUGH2, which examines multiphase flow and supercritical CO 2 behavior, were combined with the geochemical modeling capabilities of The Geochemist’s Workbench ® (GWB), using ChemPlugin TM . ChemPlugin is a self-linking re-entrant software object that, when coupled to a transport simulator, retains the flow and transport capabilities of the simulator but enables incorporation of reactive chemistry via GWB. To test and assess the capabilities of T2CPI, results from T2CPI simulations were compared to those of TOUGHREACT, using the same carbonate reservoir parameters (based on the Dollar Bay Formation of the South Florida Basin). Overall, results of simulations from TOUGHREACT and T2CPI were very similar for nearly all evaluated parameters. Dissimilarities between the two programs included qualitative differences in how TOUGHREACT and T2CPI predicted calcite dissolution and the subsequent spatial pattern of the porosity gain caused by how each handles evaporation of water near the injection point. The TOUGHREACT program is a proven, widely used tool for evaluating CO 2 –brine–rock interaction following supercritical CO 2 injection. The T2CPI tool offers similar capabilities and strengths of TOUGHREACT, with the ability to read in and use databases for a wide range of activity coefficient types. This program also has abilities to use a wide range of kinetic constraints, define those kinetic constraints with scripts or compiled libraries, account for colloidal transport, and/or account for a wide range of surface sorption models.

Florida↗

USGS2019

A probabilistic assessment methodology for carbon dioxide enhanced oil recovery and associated carbon dioxide retention

The U.S. Energy Independence and Security Act of 2007 authorized the U.S. Geological Survey (USGS) to conduct a national assessment of the potential volume of hydrocarbons recoverable by injection of carbon dioxide (CO 2 ) into known oil reservoirs with historical production. The implementation of CO 2 enhanced oil recovery (CO 2 -EOR) techniques could increase the U.S. recoverable hydrocarbon resource base. Use of anthropogenic CO 2 in the CO 2 -EOR process could reduce the amount of CO 2 released to the atmosphere by allowing a percentage of the injected CO 2 to remain in reservoir pore space once occupied by produced oil and water or by CO 2 dissolution in oil and water in the reservoir. The USGS has developed a new methodology for the national assessment of technically recoverable oil resources that may be produced by using current CO 2 -EOR technologies. The methodology relies on a proprietary reservoir-level database, the comprehensive resource database (CRD). The CRD incorporates commercially available geologic and engineering data, and USGS-defined play averages or province averages of reservoir data were used to populate incomplete records. Values from the CRD are used to estimate the original oil in place ( OOIP ) for each reservoir. The inputs are reviewed by USGS geologists, particularly when play or province averages have been used. Monte Carlo simulation is used to produce a numerical probability distribution for the OOIP for each reservoir, with the mean defined as the value of the OOIP in the CRD. A reservoir model (CO 2 Prophet, developed for the U.S. Department of Energy by Texaco, Inc.) is used to determine the incremental recovery factors for oil during the CO 2 -EOR process, on an individual reservoir basis. The model is also used to estimate the volume of CO 2 remaining in the reservoir after the CO 2 -EOR process is complete. Empirical decline curve analysis and comparison with data from published papers and reports on CO 2 -EOR projects are utilized to substantiate the simulation results. Numerical distributions of recovery factors are prepared for variations in the reservoir lithology (clastic or carbonate). The distribution of incremental oil is computed by multiplying the appropriate probability distribution of recovery factors by the individual reservoir distribution of the OOIP . A way to estimate the CO 2 remaining in the reservoir after the completion of the CO 2 -EOR process is also included in the methodology. Assessment results will be aggregated to play, petroleum province, regional, and national scales. This assessment methodology has been tested on the Horseshoe Atoll, Upper Pennsylvanian-Wolfcampian play in the Permian Basin Province in Texas; the play consists of 27 reservoirs having at least 2 billion barrels of OOIP that are amenable to the CO 2 -EOR process. The play was selected as a test case because CO 2 -EOR production data and published reports are available for several reservoirs within the play. Preliminary estimates of oil recoverable by implementation of miscible CO 2 -EOR are comparable to those reported in the literature and obtained by reservoir decline curve analysis.

Scientific Investigations Report↗

USGS2019

Geochemical data for produced waters from conventional and unconventional oil and gas wells: Results from Colorado, USA

Geochemical data for more than 120,000 oil and natural gas wells from the major sedimentary basins in the USA are listed in the USGS National Produced Waters Geochemical Database [1]. In this summary, we report and discuss the geochemical data on produced waters obtained from published literature and the Colorado Oil and Gas Conservation Commission (COGCC) from close to 4,000 new oil and gas wells in Colorado. We emphasize geochemical data of produced waters from shale and tight reservoirs that have increased dramatically in Colorado since 2011, due to deep horizontal drilling, downhole telemetry and massive multi-stage hydraulic fracturing. These operations require large volumes of fresh water, but contamination of groundwater is the major environmental concern. Also, induced seismicity caused by water injection has been reported from several areas in Colorado, including Trinidad, Raton basin, and Greely, Denver basin. Produced water salinities in Colorado obtained from unconventional oil and gas wells are relatively low, generally less than 30,000 mg/L TDS. Produced water salinities from conventional oil and gas wells overlap those from unconventional wells, but many wells have higher salinities (up to 90,000 mg/L TDS) and different chemical compositions.

Colorado↗