The impact of pressure and fluid property variation on well performance of liquid-rich Eagle Ford shale

Gherabati, S. Amin; Browning, John; Columbu, Stefano; Ikonnikova, Svetlana; McDaid, Guinevere

doi:10.1016/j.jngse.2016.06.019

Cited by 43 publications

(24 citation statements)

References 3 publications

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“…Location map showing sampled wells and oil, condensate, and gas windows, , which are color-coded by API gravity from ∼30 (blue) in oil to ∼65 (red) for dry gas.…”

Section: Methodsmentioning

confidence: 99%

“…In addition to collecting water samples, we made use of previously collected data and of existing databases (SI-D2). Gherabati et al , and Hammes et al provide estimates of porosity, water saturation, temperature, and clay volume at the sampled well locations, interpolated in-house from contour maps created using petrophysical data of ∼150 EFS wells with a comprehensive wireline log suite. Formation water content at sampled well locations was determined through the product of interpolated estimates of porosity and water saturation.…”

Section: Methodsmentioning

confidence: 99%

“…Using accurate geochemical information about formation water is important because it impacts petrophysical interpretation of well logs. For example, knowing the TDS is critical for interpreting resistivity from which water saturationsand thus oil and gas saturationscan be calculated. − Perhaps more importantly, natural low salinity also has operational implications; for example, water treatment of low-TDS water is less expensive and more amenable to recycling and other uses.…”

Section: Introductionmentioning

confidence: 99%

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Salinity Reversal and Water Freshening in the Eagle Ford Shale, Texas, USA

Nicot

Gherabati

Darvari

et al. 2018

ACS Earth Space Chem.

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Effective, considerate shale play water management supports operations and protects the environment. A parameter often overlooked is total dissolved solids (TDS) of produced water from the formation. Knowledge of TDS is important to meet these dual goals. Subsurface TDS typically increases with depth. However, produced-water samples from the Eagle Ford Shale show a strong TDS decrease by a factor of ∼10 with increasing well depth (∼200 000 ppm at ∼2.5 km to 18 000 ppm at ∼3.6 km). Water stable isotopes strongly suggest that the low TDS is not due to dilution by meteoric water. Rather, we attribute the change to smectite-to-illite conversion, in which the smectite interlayer water is released into the pore space. Depth, temperature, and other related indicators (source for K, excess silica) support such a mechanism. In addition, water-isotope patterns and 87 Sr/ 86 Sr ratios suggest a conversion operating with limited contributions external to the shale. Order-of-magnitude calculations show that the 8% of mixed-layer clay present on average in the Lower Eagle Ford Shale is sufficient to bring formation water TDS to observed levels when some of the resident water is expelled. Understanding that the low salinity is an intrinsic property of the formation water rather than due to short-term mixing allows stakeholders to have a more optimistic outlook on water recycling and on using produced water for other uses (irrigation, municipal).

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“…Location map showing sampled wells and oil, condensate, and gas windows, , which are color-coded by API gravity from ∼30 (blue) in oil to ∼65 (red) for dry gas.…”

Section: Methodsmentioning

confidence: 99%

Section: Methodsmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

See 1 more Smart Citation

Salinity Reversal and Water Freshening in the Eagle Ford Shale, Texas, USA

Nicot

Gherabati

Darvari

et al. 2018

ACS Earth Space Chem.

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“…From this experiment, we find that applying a flat C 2 H 6 :CH 4 ratio of 0.13 produces solutions for O&G emissions using the C 2 H 6 optimization that are nearly identical to the solutions from the CH 4 optimization both overall and flight‐by‐flight, with an absolute mean difference between the O&G rates per flight from these two solutions of only 0.15. The strong correlation between the results of these two optimizations after increasing the C 2 H 6 :CH 4 ratio by 80% of its original value (0.13 vs 0.07) indicates that C 2 H 6 :CH 4 emission ratios used in the simplified C 2 H 6 inventory may be significantly lower than the true ratios, and could be related to an underestimation of emissions from oil‐producing sectors of basins with a much lower percentage of CH 4 content (Gherabati et al, ; Cardoso‐Saldaña et al, ).…”

Section: Resultsmentioning

confidence: 99%

Forward Modeling and Optimization of Methane Emissions in the South Central United States Using Aircraft Transects Across Frontal Boundaries

Barkley

Davis

Feng

et al. 2019

Geophysical Research Letters

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The South Central United States is a hot spot for anthropogenic methane (CH4) emissions, with contributions from the oil/gas (O&G) and animal agriculture sectors. During frontal weather events, airflow combines enhancements from these emissions into a large plume. In this study, we take CH4 and ethane (C2H6) observations from the Atmospheric Carbon and Transport‐America campaign and adjust O&G and animal agriculture emissions such that modeled CH4 and C2H6 enhancements match the observed plume. Results from the joint CH4‐C2H6 optimization indicate that emissions from the O&G sector are 1.8 ± 0.7 (2σ) times larger than EPA inventory estimates. These results match synthesis work from recent literature and reject the possibility that this increase compared to inventories is due to a potential bias in daytime‐only measurements of these facilities. Successful modeling from this study raises the possibility of using trace gas measurements along frontal crossings to solve for emissions in other regions of the United States.

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“…Wet gas and condensate reservoirs are the intermediate zones between oil and dry gas windows. Reservoir performances were compared between East and West windows by varying fluid and reservoir properties (Gherabati et al, 2016). It was also shown that higher oil recovery was estimated in the East window due to higher reservoir pressure.…”

Section: Introductionmentioning

confidence: 99%

Productions of volatile oil and gas-condensate from liquid rich shales

Panja

Pathak

Deo

2018

Adv. Geo-Energy Res.

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The growth in productions of liquid hydrocarbons from tight formations (shales) has been phenomenal in recent years. During the production of liquids (oil and condensate), large amounts of associated gas are also produced. The economic viability of a producing well depends on maintaining a reasonable proportion of liquid. The compositions and state of reservoir fluid play an important role in producing liquids from tight formations or shales in the USA such as Eagle Ford in Texas, Niobrara in Wyoming-Colorado, and Bakken in North Dakota. Small deviation in reservoir temperature around the critical point changes the state of the fluid (volatile oil or condensate) and as a result, the production of liquid is affected. Impacts of the state of the fluid (volatile oil or condensate), reservoir permeability and operating conditions on ultimate recoveries and produced gas liquid ratio are studied here. Five different reservoir fluids representing low to high liquid hydrocarbon contents are considered. Around 2% increment in condensate recovery after 10 years of production is observed from 100 nD permeability reservoir filled with the richest fluid (fluid 5) when the well is operated at 3,000 psia compared to 1,000 psia. At the same conditions, 9.3% more condensate is recovered for the leanest fluid (fluid 1). Therefore, operating the well at higher flowing bottom hole pressure (BHP) maximized the liquid recoveries of volatile oils and condensates in case of low permeability reservoirs (100 nD). However, in case of higher permeability (1,000 nD) reservoir, lower operating pressure was preferable to increase the recovery. Conclusively, bottom hole pressure has less impact on the richer fluids and higher permeability reservoir. Operating well at higher BHP (3,000 psia) also suppresses the production of gas and relatively enhances the production of liquid. Liquid to gas ratio (LGR) declines more rapidly for 100 nD permeability reservoirs compared to 1,000 nD at BHP of 1,000 psia. High fracture permeability (1,000mD and above) appeared to negatively affect liquid recoveries at higher BHP resulting in reduction of recovery by around 2%. An optimum fracture permeability may be necessary based on reservoir permeability, operating pressure and type of fluid.

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The impact of pressure and fluid property variation on well performance of liquid-rich Eagle Ford shale

Cited by 43 publications

References 3 publications

Salinity Reversal and Water Freshening in the Eagle Ford Shale, Texas, USA

Salinity Reversal and Water Freshening in the Eagle Ford Shale, Texas, USA

Forward Modeling and Optimization of Methane Emissions in the South Central United States Using Aircraft Transects Across Frontal Boundaries

Productions of volatile oil and gas-condensate from liquid rich shales

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