scholarly journals Comparing Permitted Emissions to Atmospheric Observations of Hydrocarbons in the Eagle Ford Shale Suggests Permit Violations

Energies ◽  
2021 ◽  
Vol 14 (3) ◽  
pp. 780
Author(s):  
Joel Holliman ◽  
Gunnar W. Schade
Keyword(s):  
Oil And Gas ◽  
Gas Production ◽  
Eagle Ford Shale ◽  
Oil And Gas Development ◽  
Eagle Ford ◽  
South Central ◽  
Atmospheric Observations ◽  
Abandoned Wells ◽  
Oil And Gas Operations ◽  
Using Data

The recent decade’s rapid unconventional oil and gas development in the Eagle Ford of south-central Texas has caused increased hydrocarbon emissions, which we have previously analyzed using data from a Texas Commission on Environmental Quality air quality monitoring station located downwind of the shale area. Here, we expand our previous top-down emissions estimate and compare it to an estimated regional emissions maximum based on (i) individual facility permits for volatile organic compound (VOC) emissions, (ii) reported point source emissions of VOCs, (iii) traffic-related emissions, and (iv) upset emissions. This largely permit-based emissions estimate accounted, on average, for 86% of the median calculated emissions of C3-C6-hydrocarbons at the monitor. Since the measurement-based emissions encompass a smaller section of the shale than the calculated maximum permitted emissions, this strongly suggests that the actual emissions from oil and gas operations in this part of the Eagle Ford exceeded their permitted allowance. Possible explanations for the discrepancy include emissions from abandoned wells and high volumes of venting versus flaring. Using other recent observations, such as large fractions of unlit flares in the Permian shale basin, we suggest that the excessive venting of raw gas is a likely explanation. States such as Texas with significant oil gas production will need to require better accounting of emissions if they are to move towards a more sustainable energy economy.

scholarly journals Flaring from Unconventional Oil and Gas Development and Birth Outcomes in the Eagle Ford Shale in South Texas

2020 ◽  
Vol 128 (7) ◽  
pp. 077003 ◽  
Author(s):  
Lara J. Cushing ◽  
Kate Vavra-Musser ◽  
Khang Chau ◽  
Meredith Franklin ◽  
Jill E. Johnston
Keyword(s):  
Birth Outcomes ◽  
Oil And Gas ◽  
South Texas ◽  
Eagle Ford Shale ◽  
Oil And Gas Development ◽  
Eagle Ford ◽  
Unconventional Oil ◽  
Unconventional Oil And Gas

A Case History: Evaluating Well Completions in the Eagle Ford Shale Using a Data-Driven Approach

2015 ◽  
Author(s):  
Amir M. Nejad ◽  
Stanislav Sheludko ◽  
Robert F. Shelley ◽  
Trey Hodgson ◽  
Riley McFall
Keyword(s):  
Neural Network ◽  
Neural Network Model ◽  
Oil And Gas ◽  
Gas Production ◽  
Data Driven ◽  
Eagle Ford Shale ◽  
Eagle Ford ◽  
Oil And Gas Production ◽  
Treatment Designs ◽  
Different Parts

Abstract Unconventional shale resources are key hydrocarbon sources, gaining importance and popularity as hydrocarbon reservoirs both in the United States and internationally. Horizontal wellbores and multiple transverse hydraulic fracturing are instrumental factors for economical production from shale assets. Hydraulic fracturing typically represents a major component of total well completion costs, and many efforts have been made to study and investigate different strategies to improve well production and reduce costs. The focus of this paper is completion effectiveness evaluation in different parts of the Eagle Ford Shale Formation, and our objective is to identify appropriate completion strategies in the field. A data-driven neural network model is trained on the database comprised of multiple operators' well data. In this model, drilling and mud data are used as indicators for geology and reservoir-related parameters such as pressure, fluid saturation and permeability. Additionally, completion- and fracture-related parameters are also used as model inputs. Because wells are pressure managed differently, normalized oil and gas production is used as a model output. Thousands of neural networks are trained using genetic algorithm in order to fully evaluate hidden correlations within the database. This results in selection of a neural network that is able to understand reservoir, completion and frac differences between wells and identify how to improve future completion/stimulation designs. The final neural network model is successfully developed and tested on two separate data sets located in different parts of the Eagle Ford Shale oil window. Further, an additional test data set comprised of eight wells from a third field location is used to validate the predictive usefulness of the data-driven model. Under-producing wells were also identified by the model and new fracture designs were recommended to improve well productivity. This paper will be useful for understanding the effects of completion and fracture treatment designs on well productivity in the Eagle Ford. This information will help operators select more effective treatment designs, which can reduce operational costs associated with completion/fracturing and can improve oil and gas production.

Proppant Distribution in Newly Completed and Re-Fractured Wells - An Eagle Ford Shale Case Study

2021 ◽  
Author(s):  
Justin Allison ◽  
Glyn Roberts ◽  
Brad Hicks Hicks ◽  
Todd Lilly
Keyword(s):  
Oil And Gas ◽  
Treatment Effectiveness ◽  
Design Parameters ◽  
Distribution Analysis ◽  
Eagle Ford Shale ◽  
Eagle Ford ◽  
Video Footage ◽  
Final Consideration ◽  
Fractured Well

Abstract Fracture treatments and stage designs for new wells have evolved considerably over the past decade contributingto significant production growth. For example, in the acreage discussed hererecently used higher intensity fracturing methods provided an ~80% increase in recovery rates compared with legacy wells. Older wells completed originally with less efficient techniques can also benefit from these more up-to-date designs and treatments using re-fracturing methods. These offer the prospect of economically boosting production in appropriately selected wells. While adding in-fill wells has often been favored by Operators as a lowerrisk option the number of wells being re-fractured has grown every year for the last decade. In this case study two adjacent Eagle Ford wells, comprising a newly completed and a re-fractured well, allow both methods to be considered and compared. Completion design and fracture treatment effectiveness are evaluated using the uniformity of proppant distribution at cluster and stage level as the primary measure. Perforation erosion measurements from downhole video footage is used as the main diagnostic. Novel data acquisition methods combined with successful well preparation provided comprehensive and high-quality datasets. The subsequent proppant distribution analysis for the two wells provides the highest confidence results presented to date. Clear, repeatable trends in distribution are observed and these are compared across multiple stage designs for both the newly completed and re-fractured well. Variations in design parameters and how these effects distribution and ultimately recovery are discussed. These include changes to perforation count per cluster, cluster spacing, cluster count per stage, stage length, perforation charge size and treatment rates and volumes. As a final consideration production records for the evaluated wells are also discussed. Historical industry data shows that the number of wells being re-fractured increases relative to the number of newly drilled wells being completed during periods of low oil and gas prices. With the industry again facing harsh economic realities an increasing number of decisions will be made on whether new or refractured wells, or a combination of both, provide the best solution to replace otherwise inevitable production decline. This paper attempts to provide a detailed understanding of how proppant distribution, as a significant factor in production for hydraulically fractured wells, can be evaluated and considered in these decisions.

Effects of maturation on multiscale (nanometer to millimeter) porosity in the Eagle Ford Shale

2015 ◽  
Vol 3 (3) ◽  
pp. SU59-SU70 ◽  
Author(s):  
Lawrence Michael Anovitz ◽  
David Robert Cole ◽  
Julia Meyer Sheets ◽  
Alexander Swift ◽  
Harold William Elston ◽  
...  
Keyword(s):  
Neutron Scattering ◽  
Pore Structure ◽  
Oil And Gas ◽  
Total Porosity ◽  
The United States ◽  
Total Surface Area ◽  
Eagle Ford Shale ◽  
Rock Composition ◽  
Eagle Ford ◽  
Gas Targets

Porosity and permeability are key variables that link the thermal-hydrologic, geomechanical, and geochemical behavior in rock systems and are thus important input parameters for transport models. Neutron scattering studies indicate that the scales of pore sizes in rocks extend over many orders of magnitude from nanometer-sized pores with huge amounts of total surface area to large open fracture systems (multiscale porosity). However, despite considerable efforts combining conventional petrophysics, neutron scattering, and electron microscopy, the quantitative nature of this porosity in tight gas shales, especially at smaller scales and over larger rock volumes, remains largely unknown. Nor is it well understood how pore networks are affected by regional variation in rock composition and properties, thermal changes across the oil window (maturity), and, most critically, hydraulic fracturing. To improve this understanding, we have used a combination of small- and ultrasmall-angle neutron scattering (U)SANS with scanning electron microscope (SEM)/backscattered electron imaging to analyze the pore structure of clay- and carbonate-rich samples of the Eagle Ford Shale. This formation is hydrocarbon rich, straddles the oil window, and is one of the most actively drilled oil and gas targets in the United States. Several important trends in the Eagle Ford rock pore structure have been identified using our approach. The (U)SANS results reflected the connected (effective) and unconnected porosity, as well as the volume occupied by organic material. The latter could be separated using total organic carbon data and, at all maturities, constituted a significant fraction of the apparent porosity. At lower maturities, the pore structure was strongly anisotropic. However, this decreased with increasing maturity, eventually disappearing entirely for carbonate-rich samples. In clay- and carbonate-rich samples, a significant reduction in total porosity occurred at (U)SANS scales, much of it during initial increases in maturity. This apparently contradicted SEM observations that showed increases in intraorganic porosity with increasing maturity. Organic-rich shales are, however, a very complex material from the point of view of scattering studies, and a more detailed analysis is needed to better understand these observations.

scholarly journals Attitudes, Perceptions and Geo-Spatial Analysis of Water Quality and Individual Health Status in a High-Fracking Region

2019 ◽  
Author(s):  
Paula Stigler Granados ◽  
Zacariah L. Hildenbrand ◽  
Claudia Mata ◽  
Sabrina Habib ◽  
Misty Martin ◽  
...  
Keyword(s):  
Water Quality ◽  
Drinking Water ◽  
Health Status ◽  
Oil And Gas ◽  
Water Source ◽  
Quality Parameters ◽  
Community Members ◽  
Eagle Ford Shale ◽  
Oil And Gas Development ◽  
Private Wells

The expansion of unconventional oil and gas development (UD) across the US continues to be at the center of debates regarding safety to health and the environment. This study evaluated the water quality of private water wells in the Eagle Ford Shale within the context of community members perception. Community members (n=75) were surveyed regarding health status and perceptions of drinking water quality. Water samples (n=19) were collected from private wells and tested for a variety of water quality parameters. Of the private wells sampled, 8 had exceedences of MCLs for drinking water standards. Geospatial analysis showed the majority of well owners who did have exceedances self-reported their health status as poor. Surveys showed that the majority of respondents received their water from a municipal source and were significantly more distrustful of their water source than of those on private wells. The data also showed a high number of people self-reporting health problems without a healthcare provider’s diagnosis. Attitudes and perceptions of water quality play an important role in the overall perceived health status of community members in high fracking regions, stressing the importance of transparency and communication by the UD industry.

QUANTIFYING FRESH WATER AND PROPPANT REQUIREMENTS FOR OIL AND GAS PRODUCTION FROM THE EAGLE FORD GROUP, GULF COAST, TEXAS

2018 ◽  
Author(s):  
Nicholas J. Gianoutsos ◽  
◽  
Seth S. Haines ◽  
Brian A. Varela ◽  
Katherine J. Whidden
Keyword(s):  
Fresh Water ◽  
Oil And Gas ◽  
Gulf Coast ◽  
Gas Production ◽  
Eagle Ford ◽  
Oil And Gas Production

scholarly journals Experimental Investigation of Inhibitive Drilling Fluids Performance: Case Studies from United States Shale Basins

Energies ◽  
2020 ◽  
Vol 13 (19) ◽  
pp. 5142
Author(s):  
Nabe Konate ◽  
Saeed Salehi
Keyword(s):  
Oil And Gas ◽  
Drilling Fluid ◽  
Gas Production ◽  
Drilling Fluids ◽  
Eagle Ford Shale ◽  
Oil And Gas Production ◽  
Shale Formations ◽  
Drilling Performance ◽  
Marine Shale ◽  
Fluid Systems

Shale formations are attractive prospects due to their potential in oil and gas production. Some of the largest shale formations in the mainland US, such as the Tuscaloosa Marine Shale (TMS), have reserves estimated to be around 7 billion barrels. Despite their huge potential, shale formations present major concerns for drilling operators. These prospects have unique challenges because of all their alteration and incompatibility issues with drilling and completion fluids. Most shale formations undergo numerous chemical and physical alterations, making their interaction with the drilling and completion fluid systems very complex to understand. In this study, a high-pressure, high-temperature (HPHT) drilling simulator was used to mimic real time drilling operations to investigate the performance of inhibitive drilling fluid systems in two major shale formations (Eagle Ford Shale and Tuscaloosa Marine Shale). A series of drilling experiments using the drilling simulator and clay swelling tests were conducted to evaluate the drilling performance of the KCl drilling fluid and cesium formate brine systems and their effectiveness in minimizing drilling concerns. Cylindrical cores were used to mimic vertical wellbores. It was found that the inhibitive muds systems (KCl and cesium formate) provided improved drilling performance compared to conventional fluid systems. Among the inhibitive systems, the cesium formate brine showed the best drilling performances due to its low swelling rate and improved drilling performance.

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