Experimental insights into geochemical changes in hydraulically fractured Marcellus Shale

Marcon, Virginia; Joseph, C.; Carter, Kimberly E.; Hedges, Sheila W.; Lopano, Christina L.; Guthrie, George D.; Hakala, J. Alexandra

doi:10.1016/j.apgeochem.2016.11.005

Cited by 98 publications

(101 citation statements)

References 44 publications

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“…2) in solution (Rimstidt and Vaughan, 2003). Lowering of the pH concurrent with increases in Ca concentrations in the MSEEL core flood effluents provides evidence for calcite dissolution, which has been observed in prior batch and core flood experiments with Marcellus Shale (Dieterich et al, 2016;Marcon et al, 2017;Vankeuren et al, under review). Concurrent calcite dissolution during pyrite oxidation within shales has been observed in other studies focused on shale-fracturing fluid interactions (Wilke et al, 2015).…”

Section: Computed Tomography Scanning and Image Processingsupporting

confidence: 54%

“…Prior batch experimental studies focused on reactions between Marcellus Shale and fracturing fluids showed that, in the presence of elevated barium and fracturing chemicals, barite precipitation was either directly observed or predicted based on saturation indices calculations from experimental fluid chemistries (Dieterich et al, 2015;Marcon et al, 2017). In core flood experiments performed with laboratory-generated fracturing chemicals and core plugs derived from Marcellus Shale outcrop, barite precipitation was observed by computed tomography (CT) and scanning electron microscopy (SEM).…”

Section: Introductionmentioning

confidence: 99%

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Laboratory-Scale Studies on Chemical Reactions Between Fracturing Fluid and Shale Core From the Marcellus Shale Energy and Environmental Laboratory (MSEEL) Site

Hakala¹,

Crandall²,

Moore³

et al. 2017

Proceedings of the 5th Unconventional Resources Technology Conference

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Injection of fracturing fluids into shales during hydraulic stimulation can result in various chemical reactions involving the injected fluid and host shale rock. Differences in chemical composition between the injected fluids and fractured rock can result in mineral precipitation along shale fractures and within the shale matrix, potentially affecting long-term gas recovery from the shale. Our prior research showed that mineral precipitation and dissolution occur along freshly-generated fractures, and within the shale matrix, during core flood experiments in which laboratory-fractured Marcellus Shale was exposed to simulated hydraulic fracturing fluids. Many of the mineral precipitation reactions were hypothesized to occur due to the inability for antiscaling compounds in the fracturing fluids to control mineral precipitation at elevated temperature and pressure. In some locations along the fracture, proppant was cemented to shale surfaces through secondary mineral precipitates. The present study focuses on core flood experiments using fresh core and site hydraulic fracturing fluid from the Marcellus Shale Energy and Environmental Laboratory site (MSEEL; Morgantown, WV) at reservoir pressure and temperature conditions. The objectives of this study are to evaluate the reproducibility of the earlier experiments using fresh core, and to identify causes for any observed differences with the prior outcrop-based experiments.

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Section: Computed Tomography Scanning and Image Processingsupporting

confidence: 54%

Section: Introductionmentioning

confidence: 99%

Laboratory-Scale Studies on Chemical Reactions Between Fracturing Fluid and Shale Core From the Marcellus Shale Energy and Environmental Laboratory (MSEEL) Site

Hakala¹,

Crandall²,

Moore³

et al. 2017

Proceedings of the 5th Unconventional Resources Technology Conference

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“…These values were used to best mimic in situ reservoir conditions of the Marcellus Shale while remaining within the limitations of the vessels. Inside each 600 ml pressure vessel, a small Teflon cup was placed containing a fixed HFF-shale ratio (20:1) following research done by similar studies conducted at NETL Pittsburgh (Marcon et al, 2017).…”

Section: Experimental Set-upmentioning

confidence: 99%

“…On average roughly 40% of this fluid returns to the surface upon completion and is then considered produced fluid. Produced fluid has a chemical signature distinctly different from the initially injected HFF (Strong et al, 2014, Hoelzer, et al, 2016, Marcon, et al, 2017 and the copious amounts of fluid generated from thousands of wells drilled within the Marcellus Shale necessitate a better understanding of reactions occurring between HFF and the shale reservoir. Recycling and remediation efforts of produced fluid are of great concern to industry, environmental scientists, and the general public.…”

Section: Introductionmentioning

confidence: 99%

“…The breaker creates SO4 2free radical ions at elevated temperatures (Tasker et al, 2016), which react with the linkages of the polymer structure, breaking up the compounds and allowing the fluid to flow back to the surface. Both experimental and field samples have proven that the chemical signature of produced fluid can be significantly different from the initial injection fluid (Strong et al, 2014, Hoelzer, et al, 2016, Marcon, et al, 2017. Produced water is typically characterized by its relatively high TDS,…”

Section: Introductionmentioning

confidence: 99%

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Effect of maturity and mineralogy on fluid-rock reactions in the Marcellus Shale

Pilewski

Sharma

Hakala

et al. 2019

Environ. Sci.: Processes Impacts

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EFFECT OF MATURITY AND MINERALOGY ON FLUID-ROCK REACTIONS IN THE MARCELLUS SHALE John PilewskiThe advancement in drilling technology and discoveries of large quantities of natural gas in the United States has led to a substantial increase in hydraulic fracturing (HF) operations in the past two decades. The Marcellus Shale is a world-renowned source rock that has been extensively exploited via HF, and this study aims to analyze the complex chemical reactions that take place during this process of hydrocarbon extraction. Fluid-shale reactions were conducted using a mixture of synthetic brine, and synthetic hydraulic fracturing fluid reacted with three shale samples of varying maturity and mineralogy. Static autoclave reactors were used to mimic in situ reservoir reaction parameters, roughly 2,500 psi and 100°C respectively. Reactions were carried out for 14 days in accordance with the shut-in time when fluid remains in the reservoir during the HF process. The chemical analysis focused on observing major changes in ionic species concentrations and the proliferation of low molecular weight organic compounds with respect to maturity and mineralogy. Shale samples LM-2 and MIP-3H containing relatively greater amounts of carbonate minerals reacted as buffering agents during the reaction increasing the effluent pH to near neutral. Ion Chromatography results indicate an increase in sulfate and phosphate ions and decrease in barium ions in all fluid-shale effluents. These results suggest that the relative abundance of minerals, particularly calcite and pyrite, affect mineral dissolution and precipitation during HF operations. Results also show organic acids are generated in the control fluid, HPT-PF, by placing it under high pressure/temperature conditions without any shale interaction. Overall dissolved organic carbon concentrations decrease in all effluent samples compared to the control fluid. The GC-MS analysis focused on the observation of benzene, toluene, ethylene, and xylene (BTEX) analytes. Results indicate toluene and xylene were generated in the control fluid, HPT-PF, without any shale interaction. The least mature LM-2 sample generated effluent containing the highest concentrations of target VOC analytes, and the most mature MIP-3H sample generated no observable analytes. These results suggest that HFF additives are being transformed at reservoir pressure/temperature conditions, low mature shale is releasing geogenic, labile organic compounds, and high mature shale is adsorbing any VOCs generated from HF processes.iii

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Geochemical phenomena between Utica‐Point Pleasant shale and hydraulic fracturing fluid

2019

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This study evaluated geochemistry between the Utica-Point Pleasant shale and reservoir/hydraulic fracturing fluid mixtures under simulated reservoir conditions in a batch reactor system. Analytical techniques were utilized to monitor fluid composition with time along with pre-and post-trial shale microscopy and phase identification analyses. Formation of iron-based precipitate was evident through results from fluid and material analyses. Ferrous iron was the predominant iron form found in the aqueous phase, with oxidation to ferric iron and subsequent precipitate formation. Geochemical modeling further supported ferric iron was the favorable phase for precipitation. K E Y W O R D S crystallization (precipitation), geochemical, hydraulic fracturing, oil shale/tar sands, reaction kinetics 1 | INTRODUCTION U.S. tight oil has had a tremendous impact on stabilizing global oil prices and increasing energy security. Such light crude is recovered from low permeability rock formations, primarily shale, using unconventional methods such as horizontal drilling with hydraulic fracturing. As of March 2019, the Energy Information Association (EIA) reports approximately 60% total U.S. oil production comes from tight oil. 1 While unconventional wells have shown promise in terms of oil production, economic viability is still uncertain due to rapid production decline leading to shorter well life. Peak performance of an unconventional oil well occurs during the first quarter of production, with up to 74% production decline after 1 year. 2 Solutions explored to counteract production decline include refracturing or other enhanced oil recovery methods. Simulation studies have been developed to evaluate the effects of stimulation techniques on production to determine if profitable recovery is feasible. 3-5 Although simulation of refracturing and enhanced oil recovery methods have shown promise, these techniques do not fully account for phenomena encountered in unconventional wells. Various approaches have been utilized to mimic downhole phenomena. 6-8 An approach by Luo evaluated confinement effects on hydrocarbon bubble point. This study found octane and decane confined in nanoporous media possess two distinct bubble point temperatures, with lower/higher bubble point temperatures differing ±15 K in comparison to respective bulk properties. 6 By understanding various in-situ well phenomena, proper recovery analysis can be performed and modifications to hydraulic fracturing processes can be developed to increase well productivity and lifetime. 9 Aqueous phase chemical reactions are another key phenomenon occurring in shale reservoirs. Such reactions occur during well completion, when hydraulic fracturing fluid (HFF) mixes with rock and formation water, potentially causing precipitate formation, more commonly referred to as scale. Scales form when dissolved solid concentrations This contribution was identified by Rameshwar Srivastava (Department of Energy) as the Best Presentation in the session "New Technologies to Enhance the Productio...

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Experimental insights into geochemical changes in hydraulically fractured Marcellus Shale

Cited by 98 publications

References 44 publications

Laboratory-Scale Studies on Chemical Reactions Between Fracturing Fluid and Shale Core From the Marcellus Shale Energy and Environmental Laboratory (MSEEL) Site

Laboratory-Scale Studies on Chemical Reactions Between Fracturing Fluid and Shale Core From the Marcellus Shale Energy and Environmental Laboratory (MSEEL) Site

Effect of maturity and mineralogy on fluid-rock reactions in the Marcellus Shale

Geochemical phenomena between Utica‐Point Pleasant shale and hydraulic fracturing fluid

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