Geology Reports⌕ Search

Geology topics

Brian A. Varela

Publications and source records attributed to Brian A. Varela.

At least 19 recordsLinked to original sources
USGS2026

Assessment of water and proppant quantities associated with hydrocarbon production from the Haynesville Formation within the onshore United States and State waters of the Gulf Coast Basin, 2024

Building on a geology-based assessment of undiscovered, technically recoverable hydrocarbon resources within the Haynesville Formation, the U.S. Geological Survey estimated the water and proppant necessary for development of the remaining resources associated with the Haynesville Sabine Uplift Continuous Gas Assessment Unit. Additionally, projections have been made on the volume of wastewater expected as a byproduct of possible future development. This fact sheet presents an overview of the methodology, along with the inputs and results of the Haynesville water and proppant assessment.

Alabama, Arkansas, Florida, Louisiana, Mississippi↗
USGS2025

A probabilistic assessment methodology for the evaluation of geologic energy storage capacity—Natural gas storage in depleted hydrocarbon reservoirs

The need for energy storage, particularly underground, where capacity and duration may far exceed battery storage technologies, is especially relevant given the increasing demands for reliable power alongside the development of intermittent renewable electricity sources. Geologic energy storage facilities already exist, and expanded use would enable storing gases such as methane and hydrogen. In 2018, a National Academies of Sciences, Engineering, and Medicine report, “Future Directions for the U.S. Geological Survey's Energy Resources Program,” recommended that the U.S. Geological Survey (USGS) prioritize assessing underground energy storage in geologic formations in the United States. The U.S. Geological Survey has since developed a methodology for assessing natural gas storage capacities in depleted hydrocarbon reservoirs on a national scale. The methodology introduced in this report prescribes three approaches for calculating gas storage capacity. This methodology relies on the availability of input data, including cumulative hydrocarbon production records, reservoir petrophysical properties, and reservoir pressure data. Assessment inputs can be obtained from public, State-level databases and propriety national-scale databases, although the use of analogs could be warranted for estimating input parameters. Probabilistic assessment results are aggregated to play, petroleum province, regional, and national scales. The steps defined in this report are demonstrated on the Michigan Basin Province, which includes the Mississippian Sandstone Gas Play and the Clinton Structural Play. This methodology could be used to systematically and consistently assess hydrocarbon plays and provinces for natural gas storage capacity across the United States.

Michigan↗
USGS2025

Methodology for defining and compiling abandoned and active hydrocarbon well inventories

Hydrocarbon wells are not active forever; when they become permanently disused (abandoned), well infrastructure must be remediated or repurposed. Knowing which wells are abandoned is the initial and often complicated step in taking responsibility for well infrastructure. Each State creates laws and regulates hydrocarbon operations, which includes well abandonment. The existence of multiple regulating authorities means definitions of abandonment are mostly found in legal documents are broadly defined or other terms are used. This report presents a technical approach to defining hydrocarbon well abandonment using well production data and identifies abandoned hydrocarbon wells using the new definition.

Scientific Investigations Report↗
USGS2024

How quickly do oil and gas wells “Water Out”? Quantifying and contrasting water production trends

Water production from petroleum (oil and natural gas) wells is a topic of increasing environmental and economic importance, yet quantification efforts have been limited to date, and patterns between and within petroleum plays are largely unscrutinized. Additionally, classification of reservoirs as “unconventional” (also known as “continuous”) carries scientific and regulatory importance, but in some cases the distinction from "conventional" wells is unclear. Using water, oil, and gas production data, we calculated a set of quantitative metrics that elucidate trends in the water-to-petroleum ratio over the life of each producing well. The percent growth of the water-to-petroleum ratio quantifies the degree to which a well “waters out” over time; values calculated for 153,900 wells in 18 oil and gas plays show generally much higher values for conventional wells than for continuous/unconventional wells. Analysis of the percent growth along with the slope and median metrics reveals greater variation between conventional plays and between continuous (unconventional) plays than previously recognized. Further, an example from the Bakken Formation in the Williston Basin, USA, illustrates that, within a single play, the metrics provide insight into spatial variation of water production trends, as influenced by geology and reservoir characteristics. By quantifying the variability of water production trends within individual plays and between plays, including differences between conventional and continuous (unconventional) plays, these results provide a more nuanced view of water production from oil and gas wells than has previously been possible and they illustrate the degree to which water management considerations vary spatially and temporally.

Natural Resources Research↗
USGS2024

Examining water and proppant demand, and produced water production, associated with petroleum resource development in the Eagle Ford Group, Texas

More than 20,000 horizontal wells have been drilled and hydraulically fractured in the Eagle Ford Group since the discovery well in 2008, but a considerable amount of undiscovered petroleum remains. Recently, drilled wells have been hydraulically fractured with an average of nearly 13 million gallons of water and 16 million lb of sand, yielding a million or more gallons of produced water. To inform future petroleum development in the Eagle Ford, the U.S. Geological Survey (USGS) conducted a water and proppant assessment using a geology-based approach that builds on the 2018 USGS assessment of undiscovered technically recoverable petroleum. Using probabilistic input values and a Monte Carlo simulation, we determined that production of the remaining undiscovered technically recoverable oil and gas in the Eagle Ford Group would require approximately 687,565 Mgal (millions of gallons) of water and 839,702,000,000 lb of proppant (both are mean values of output distributions). This possible future petroleum production would also include 176,817 Mgal (mean value) of produced formation water. On average, oil wells require water volumes that are approximately twice the volume of oil that will be produced, and Eagle Ford gas wells require approximately 5.21 Mgal of water per billion cubic feet of gas (bcfg). Produced formation water volumes are approximately 60% of the produced oil volume and, for gas wells, will yield approximately 1 Mgal formation water per bcfg. Understanding the water and proppant requirements associated with petroleum exploration and the resulting volume of produced water can inform decisions regarding the future of Eagle Ford development.

Texas↗
USGS2024

A methodology to estimate CO2 and energy gas storage resources in depleted conventional gas reservoirs

Depleted hydrocarbon reservoirs are subsurface geological structures capable of sequestering vast quantities of carbon dioxide (CO 2 ) as well as storing other energy gases for later usage, such as natural gas, and potentially hydrogen (H 2 ). Here we outline a methodology to quantify multi-gas storage resources in depleted conventional gas reservoirs for usage in assessments by the United States Geological Survey (USGS) at the scale of sedimentary basins. The methodology consists first of quantifying accessible pore volume in a depleted reservoir for natural gas storage using up to three equations. Input data are derived from commonly reported or estimated reservoir parameters and natural gas production volumes, and equations may be combined in linear models to improve pore volume estimates. Storage estimates from these equations are tested and validated for 31 reservoirs in the Michigan Basin Province, USA that were previously converted to underground gas storage facilities and have known (federally reported) natural gas storage capacities. Secondly, natural gas storage capacities can be transformed via fluid substitution calculations to estimate the storage resources for non-native fluids, applied here for, CO 2 , H 2 , and methane-H 2 blends, accounting for molecule-specific deviations from ideal gas behavior at reservoir pressures and temperatures as well as differing storage efficiencies. Importantly, the storage of non-native fluids may not be appropriate in all depleted gas reservoir settings due to potential risks like leakage, in particular in the case of H 2 storage, requiring additional knowledge of caprock sealing capacity. Given this caveat, we demonstrate the fluid substitution method for natural gas reservoirs of the Northern Niagaran Reef and Southern Niagaran Reef USGS plays in the Michigan Basin Province, as these trends of Silurian pinnacle reefs are capped with tight-sealing evaporite facies. The deterministic equations outlined from this methodology can be incorporated into future probabilistic USGS gas storage assessments for CO 2 , H 2 , and natural gas resources in the United States.

Michigan↗
USGS2024

New methodology for assessing underground natural gas storage resources – Example from Michigan Basin, United States

Energy consumption in the United States (U.S.) and across the world is shifting away from traditional fossil fuels like coal and oil, and towards natural gas and renewable sources, including hydrogen. Because gas demand is typically greatest during cold seasons and renewable sources sometimes produce variable supplies, it is important to store energy for use when demand exceeds supply. Whereas batteries and tanks typically store energy above ground, geologic (underground) storage may be able to retain much greater quantities of energy over much longer durations (e.g., Matos et al. 2019; Buursink et al. 2023). Consequently, the U.S. Geological Survey (USGS) is developing a methodology to locate new geologic energy storage sites with an initial focus on depleted hydrocarbon reservoirs followed by estimates of associated pore space or gas storage capacity. Depleted hydrocarbon fields in Michigan Basin in the U.S. already host large quantities of injected natural gas (about 681 billion cubic feet of seasonal gas capacity in 42 gas storage facilities; U.S. Energy Information Administration 2024). Therefore, we used this basin as an example to assess potential new storage resources alongside existing storage capacity and carbon dioxide sequestration resources (e.g., Katz and Coats 1968; Haagsma et al. 2020). In Michigan Basin gas storage is taking place in reservoirs within several key hydrocarbon producing formations with different lithologies, including the informal Stray sandstone of the Michigan Formation and the pinnacle reefs of the Niagara Group (Gautier et al. 1995; Swezey et al. 2015). The assessment methodology introduced here consists of two steps relying on both well information and reservoir data.

Michigan↗
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

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

Method for compiling temporally and spatially aggregated data on hydraulic fracturing—Treatments and wells

This report provides a step-by-step method for compiling hydraulic fracturing data in the United States from the IHS Markit, 2019, U.S. Well History and Production Relational Database. Data on hydraulically fractured wells include their location (geologic province, State, county), well type (oil or gas), orientation (directional, horizontal, or vertical), spud date, completion date and the hydraulic fracturing treatments, treatment fluids types, treatment fluid volumes, additive types, agent types (“proppants”), and proppant amounts injected. This method also describes how to associate each unique well with the hydraulic fracturing treatments to provide an indication of the total amount of all treatment fluids injected into a well for hydraulic fracturing and the volume of each individual treatment fluid type injected.

Open-File Report↗
USGS2020

Assessment of undiscovered oil and gas resources in the Upper Cretaceous Austin Chalk and Tokio and Eutaw Formations, U.S. Gulf Coast, 2019

Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable mean resources of 6.9 billion barrels of oil and 41.5 trillion cubic feet of natural gas in conventional and continuous accumulations in the Upper Cretaceous Austin Chalk and Tokio and Eutaw Formations onshore and in State waters of the U.S. Gulf Coast region.

Alabama, Arkansas, Louisiana, Mississippi, Oklahom↗
USGS2020

Assessment of water and proppant quantities associated with petroleum production from the Eagle Ford Group, Gulf Coast, Texas, 2019

Building on a geology-based assessment of undiscovered, technically recoverable petroleum resources in the Eagle Ford Group in south Texas, the U.S. Geological Survey has estimated the required water and proppant demands and formation water production volumes associated with possible future development of these petroleum resources. The results of the water and proppant assessment are presented here, along with related drilling information and relevant water budget volumes for the region.

Texas↗
USGS2019

Hydrocarbons in upland groundwater, Marcellus Shale Region, Northeastern Pennsylvania and Southern New York, USA

Water samples from 50 domestic wells located <1 km (proximal) and >1 km (distal) from shale-gas wells in upland areas of the Marcellus Shale region were analyzed for chemical, isotopic, and groundwater-age tracers. Uplands were targeted because natural mixing with brine and hydrocarbons from deep formations is less common in those areas compared to valleys. CH 4 -isotope, predrill CH 4 -concentration, and other data indicate that one proximal sample (5% of proximal samples) contains thermogenic CH 4 (2.6 mg/L) from a relatively shallow source (Catskill/Lock Haven Formations) that appears to have been mobilized by shale-gas production activities. Another proximal sample contains five other volatile hydrocarbons (0.03–0.4 μg/L), including benzene, more hydrocarbons than in any other sample. Modeled groundwater-age distributions, calibrated to 3 H, SF 6 , and 14 C concentrations, indicate that water in that sample recharged prior to shale-gas development, suggesting that land-surface releases associated with shale-gas production were not the source of those hydrocarbons, although subsurface leakage from a nearby gas well directly into the groundwater cannot be ruled out. Age distributions in the samples span ∼20 to >10000 years and have implications for relating occurrences of hydrocarbons in groundwater to land-surface releases associated with recent shale-gas production and for the time required to flush contaminants from the system.

New York, Pennsylvania↗
USGS2019

Carbon dioxide enhanced oil recovery and residual oil zone studies at the U.S. Geological Survey

The U.S. Geological Survey (USGS) is preparing a national resource assessment of the potential hydrocarbons recoverable after injection of carbon dioxide (CO2) into conventional oil reservoirs in the United States. The implementation of CO2-enhanced oil recovery (CO2-EOR) techniques can increase hydrocarbon production, and lead to incidental retention of CO2 in reservoir pore space allowing long-term storage of anthropogenic CO2. A Comprehensive Resource Database (CRD) containing proprietary data on location, geologic, petrophysical, and reservoir parameters, plus production and well counts for major oil and gas reservoirs in onshore areas and State waters of the conterminous United States and Alaska, was developed to support the USGS assessment. Residual oil zones (ROZs) also can provide potential pore space for long-term storage of anthropogenic CO2. However, ROZs are not included in the upcoming USGS national CO2-EOR assessment because assessment methods for ROZs still are being developed. Additional ROZ CO2-EOR and CO2 retention data and reservoir simulations are needed to calibrate national ROZ assessment estimates.

Conference Paper↗
USGS2018

U.S. Geological Survey input-data forms for the assessment of the Upper Jurassic Haynesville Formation, U.S. Gulf Coast, 2016

Introduction In 2016, the U.S. Geological Survey (USGS) completed an updated assessment of undiscovered, technically recoverable oil and gas resources in the Upper Jurassic Haynesville Formation of the onshore U.S. Gulf Coast Province (Paxton and others, 2017). The Haynesville Formation was assessed using both the standard continuous (unconventional) and conventional methodologies established by the USGS for four assessment units (AUs): (1) Haynesville Western Shelf Carbonate Gas and Oil AU, (2) Haynesville Eastern Shelf Sandstone and Carbonate Oil and Gas AU, (3) Haynesville Shale Continuous Gas AU, and (4) Haynesville Shale Peripheral Continuous Gas AU. The revised assessment resulted in total estimated mean resources of 1.1 billion barrels of oil, 195.8 trillion cubic feet of gas, and 866 million barrels of natural gas liquids. The purpose of this report is to provide supplemental documentation of the input parameters used in the USGS 2016 Haynesville Formation assessment.

Open-File Report↗
USGS2018

U.S. Geological Survey input-data forms for the assessment of the Upper Jurassic Bossier Formation, U.S. Gulf Coast, 2016

Introduction In 2016, the U.S. Geological Survey (USGS) completed an updated assessment of undiscovered, technically recoverable oil and gas resources in the Upper Jurassic Bossier Formation of the onshore U.S. Gulf Coast Province (Paxton and others, 2017). The Bossier Formation was assessed using both the standard continuous (unconventional) and conventional methodologies established by the USGS for three assessment units (AUs): (1) Bossier Eastern Shelf Sandstone Gas and Oil AU, (2) Bossier Western Shelf Sandstone Gas AU, and (3) Bossier Shale Continuous Gas AU. A fourth assessment unit, the Upper Jurassic Downdip Continuous Gas AU, was also defined but was not quantitatively assessed because of limited well data within the extent of the AU. The revised assessment resulted in total estimated mean resources of 2.9 billion barrels of oil, 108.6 trillion cubic feet of gas, and 1.1 billion barrels of natural gas liquids. The purpose of this report is to provide supplemental documentation of the input parameters used in the USGS 2016 Bossier Formation assessment.

Open-File Report↗