Assessment of water and proppant quantities associated with petroleum production from the Bakken and Three Forks Formations, Williston Basin Province, Montana and North Dakota, 2016

Haines, Seth S.; Varela, Brian A.; Hawkins, Sarah J.; Gianoutsos, Nicholas J.; Thamke, Joanna N.; Engle, Mark A.; Tennyson, Marilyn E.; Schenk, Christopher J.; Gaswirth, Stephanie B.; Marra, Kristen R.; Kinney, Scott A.; Mercier, Tracey J.; Martinez, Cericia

doi:10.3133/fs20173044

Cited by 9 publications

(12 citation statements)

References 3 publications

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“…All well locations remaining for future drilling are assumed to be developed in TRR assessments, and technology is defined by recent trends and does not change in the future. This is the standard approach used by the U.S. Geological Survey, the primary agency tasked with U.S. resource assessments, and has been applied in several plays. − …”

Section: Materials and Methodsmentioning

confidence: 99%

Will Water Issues Constrain Oil and Gas Production in the United States?

Scanlon

Ikonnikova

Qin-ke

et al. 2020

Environ. Sci. Technol.

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The rapid growth in U.S. unconventional oil and gas has made energy more available and affordable globally but brought environmental concerns, especially related to water. We analyzed the water-related sustainability of energy extraction, focusing on: (a) meeting the rapidly rising water demand for hydraulic fracturing (HF) and (b) managing rapidly growing volumes of water co-produced with oil and gas (produced water, PW). We analyzed historical (2009–2017) HF water and PW volumes in ∼73 000 wells and projected future water volumes in major U.S. unconventional oil (semiarid regions) and gas (humid regions) plays. Results show a marked increase in HF water use, and depleting groundwater in some semiarid regions (e.g., by ≤58 ft [18 m]/year in Eagle Ford). PW from oil reservoirs (e.g., Permian) is ∼15× higher than that from gas reservoirs (Marcellus). Water issues related to both HF water demand and PW supplies may be partially mitigated by closing the loop through reuse of PW for HF of new wells. However, projected PW volumes exceed HF water demand in semiarid Bakken (2.1×), Permian Midland (1.3×), and Delaware (3.7×) oil plays, with the Delaware oil play accounting for ∼50% of the projected U.S. oil production. Therefore, water issues could constrain future energy production, particularly in semiarid oil plays.

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Section: Materials and Methodsmentioning

confidence: 99%

Will Water Issues Constrain Oil and Gas Production in the United States?

Scanlon

Ikonnikova

Qin-ke

et al. 2020

Environ. Sci. Technol.

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“…There have been considerable advancements in completion methods with respect to fracturing domain over the past few decades. Frac and pack, hydra-jet perforation, zipper fracking, proppant selection, fracturing fluid optimization, and fracture mapping coupled with microseismicity are some technologies that aided in the economical and efficient recovery from tight reservoirs. − …”

Section: Methodsmentioning

confidence: 99%

Hydraulic Fracturing Design Considerations and Optimal Usage of Water Resources for Middle Eastern Tight Gas Reservoirs

2021

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Over the past few decades, hydraulic fracturing, a well-stimulation technique commonly used for extracting hydrocarbons within unconventional reservoirs, has played a significant role in transforming the energy industry. Multiple studies and field trials have proven that an effective, efficient, and economical approach is critical for such operations. However, even after numerous fracturing jobs conducted across the globe, they are still related with high risk. Moreover, the exploitation of such reservoirs is water- and resource-intensive as compared to conventional reservoirs. This is crucial, especially in offshore operations and arid regions. A comprehensive investigation through a traditional fracture design process was conducted for a candidate Middle Eastern reservoir. Through the construction of strategically constrained cases in the presence of complex natural fracture sets, this novel investigation allowed the model to successfully isolate and characterize the key fracture design parameters that influenced fracture geometry for the candidate field and in turn the requirements with respect to water usage and resource consumption. The results indicate that for the given field conditions, fluid and proppant optimization is critical to achieving maximum recovery. The influence of natural fracture is highly critical and greatly influences the overall productivity. Simulations further indicate water requirements for the candidate field ranging from 3.5 to 5.8 million gallons of water per operation, which is significant in water-scarce regions. The findings of this study and the proposed workflow can assist to better understand the distinct contributions of key fracture design and operational parameters that are critical under the current volatile market conditions.

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“…The transition time between flowback to natural formation brine is unclear, in part because there is no absolute definition of flowback water and wide variability (6–85 percent) in hydraulic fracturing fluid volumes reported to return to the surface. − As such, the actual flowback volumes are challenging to ascertain if flowback is identified based solely on time since hydraulic fracturing. Flowback has been considered to be the water produced anytime from the first 14 to 90 days following hydraulic fracturing .…”

Section: Introductionmentioning

confidence: 99%

“…Flowback has been considered to be the water produced anytime from the first 14 to 90 days following hydraulic fracturing . The flowback has also been defined as the water produced during the period of decline following either the initially high water-to-oil ratio (monthly barrels of water produced per barrel of oil, WOR) or the initially high volume of water produced immediately following hydraulic fracturing until a steady-state rate is achieved. , These differing definitions may be the reason why it remains “unclear how long the injected fracturing fluids affect the composition of produced water generation”…”

Section: Introductionmentioning

confidence: 99%

“…8 The flowback has also been defined as the water produced during the period of decline following either the initially high water-to-oil ratio (monthly barrels of water produced per barrel of oil, WOR) or the initially high volume of water produced immediately following hydraulic fracturing until a steady-state rate is achieved. 5,9 These differing definitions may be the reason why it remains "unclear how long the injected fracturing fluids affect the composition of produced water generation". 2 The isotopic and geochemical constituents in produced water 8,10−15 have been measured following hydraulic fracturing in time-series studies to help distinguish flowback fluids from natural formation brine.…”

Section: ■ Introductionmentioning

confidence: 99%

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Insights on Geochemical, Isotopic, and Volumetric Compositions of Produced Water from Hydraulically Fractured Williston Basin Oil Wells

Gallegos

Doolan

Caldwell

et al. 2021

Environ. Sci. Technol.

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Tracing produced water origins from wells hydraulically fractured with freshwater-based fluids is sometimes predicated on assumptions that (1) each geological formation contains compositionally unique brine and (2) produced water from recently hydraulically fractured wells resembles fresher meteoric water more so than produced water from older wells. These assumptions are not valid in Williston Basin oil wells sampled in this study. Although distinct average 228Ra/226Ra ratios were found in water produced from the Bakken and Three Forks Formations, average δ2H, δ18O, specific gravity, and conductivity were similar but exhibited significant variability across five oil fields within each formation. Furthermore, initial produced water (“flowback”) was operationally defined based on the presence of glycol ether compounds and water from wells that had produced <56% of the amount of fluids injected and sampled within 160 days of fracturing. Flowback unexpectedly exhibited higher temperature, specific gravity, conductivity, δ2H, and δ18O, but lower oxidation–reduction potential and δ11B, relative to the wells thought to be producing formation brines (from wells with a produced-to-injected water ratio [PIWR] > 0.84 and sampled more than 316 days after fracturing). As such, establishing an overall geochemical and isotopic signature of produced water compositions based solely on chemical similarity to meteoric water and formation without the consideration of well treatments, well completion depth, or lateral location across the basin could be misleading if these signatures are assumed to be applicable across the entire basin. These findings have implications for using produced water compositions to understand the interbasin fluid flow and trace sources of hydraulic fracturing fluids.

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Assessment of water and proppant quantities associated with petroleum production from the Bakken and Three Forks Formations, Williston Basin Province, Montana and North Dakota, 2016

Cited by 9 publications

References 3 publications

Will Water Issues Constrain Oil and Gas Production in the United States?

Will Water Issues Constrain Oil and Gas Production in the United States?

Hydraulic Fracturing Design Considerations and Optimal Usage of Water Resources for Middle Eastern Tight Gas Reservoirs

Insights on Geochemical, Isotopic, and Volumetric Compositions of Produced Water from Hydraulically Fractured Williston Basin Oil Wells

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