Experimental and predicted geochemical shale-water reactions: Roseneath and Murteree shales of the Cooper Basin

Pearce, Jon; Turner, Luc G.; Pandey, Deepak

doi:10.1016/j.coal.2017.12.008

Cited by 41 publications

(45 citation statements)

References 26 publications

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“…17 A limited set of studies have been performed to replicate the geochemistry and conditions in unconventional reservoirs during completion; however, only select studies have characterized precipitate products. 11,[18][19][20][21][22][23][24] A study by Dieterich, indicated an in-situ scale formation may occur between Marcellus shale and synthetic HFF and Huntersville Chert exposed to recycled HFF at reservoir conditions. This study found formation of gypsum (CaSO 4 Á2H 2 O) on the Marcellus shale, while formation of barite (BaSO 4 ), strontianite (SrCO 3 ), celestine (SrSO 4 ) and apatite (Ca 5 (PO 4 ) 3 (F,Cl,OH)) on Hunterville Chert.…”

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confidence: 99%

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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confidence: 99%

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

2019

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“…Because O 2 is present in FRW and atmospheric O 2 is entrained in the injected FRW (Xu et al, 2018;Zolfaghari et al, 2016) and other oxidizers (such as a persulfate breaker or H 2 O 2 ) are added to fracturing fluids at shale gas sites (Osselin et al, 2019;Phan et al, 2020), and because there are always pyrite minerals in shales (Heller & Zoback, 2014), oxidation of pyrites after hydraulic fracturing and during initial flowback is very likely (Osselin et al, 2019;Paukert Vankeuren et al, 2017;Xu et al, 2018;Zolfaghari et al, 2016). Laboratory experiments have revealed evidence for oxidation of pyrites (Pearce et al, 2018;Xu et al, 2018; d and e in Figure 4), which would contribute additional SO 4 to the FBW. However, in our field experiment, even an additional 10 mg/L of SO 4 derived from the oxidation of pyrite in the shale at the initial stage of flowback (158 + 10 mg/L) would deviate from the mixing line (g in Figure 4), suggesting that the data did not provide evidence for pyrite oxidation.…”

Section: Geophysical Research Lettersmentioning

confidence: 99%

Identification of Geochemical Processes During Hydraulic Fracturing of a Shale Gas Reservoir: A Controlled Field and Laboratory Water‐Rock Interaction Experiment

Huang

Mayer

et al. 2020

Geophysical Research Letters

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A detailed study on geochemical processes following hydraulic fracturing can provide important information on the origin of solutes and potential improvement of fracturing technology. However, this remains difficult due to the low resolution of flowback water and high salinity of formation water. To fill this knowledge gap, a shale-gas well was drilled and freshwater was used to fracture the shale. In parallel, laboratory water-rock interaction experiments were conducted. The intensive sampling for flowback water and the use of multiple isotopes provided novel and detailed insights into the water-rock interactions after hydraulic fracturing. The results showed that beyond mixing processes, cation exchange, adsorption/desorption, and barite precipitation were observed both in the laboratory and field studies. Although oxidation of pyrite was observed in most of the laboratory experiments, our findings demonstrate that this process was not evident in field flowback samples that were dominated by mixing of fracturing fluids and formation water. Plain Language Summary The hydraulic fracturing technologies have paved the way toward the development of unconventional shale gas from low-permeability shale reservoirs. The solutes in flowback water after hydraulic fracturing of shale gas reservoirs can originate from injected fracturing fluids and formation water, but may also be derived from solutes liberated by geochemical reactions. However, in most cases, the laboratory data do not match the field data from hydraulically fractured wells. To date, a further refined understanding of geochemical reactions after hydraulic fracturing occurred is critical for tracing the origin of solutes in flowback water (as the main potential pollutants for near-surface environments) and potentially improving the fracturing technology. Except for reported cation exchange and carbonate dissolution, this study showed several new findings, including nitrate adsorption/desorption and limited oxidation of pyrite in field flowback samples that were dominated by mixing of fracturing fluids and formation water, although oxidation of pyrite was observed in most of the laboratory experiments and expected to be comprehensive during field flowback after hydraulic fracturing. Therefore, the potential creation of matrix porosity induced by water-rock interactions of oxidation of pyrite and further induced dissolution of minerals may be limited.

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“…Efforts in modelling have mainly focused on flow transport with changes to advective flow due to the decreasing subsurface pressure linked to gas extraction (Karra et al, 2015). However, a late-stage decrease in production could also be caused by clogging of pores and fractures due to mineral precipitation (Jew et al, 2017;Pearce et al, 2018). Experiments have indicated that pyrite dissolution can become inhibited over time by the formation of Fe(OH)3 as a surface coating in particular at higher fluid pH (Harrison et al, 2017;Kamei and Ohmoto, 2000).…”

Section: Introductionmentioning

confidence: 99%

“…Experiments have indicated that pyrite dissolution can become inhibited over time by the formation of Fe(OH)3 as a surface coating in particular at higher fluid pH (Harrison et al, 2017;Kamei and Ohmoto, 2000). The formation of these secondary precipitates can attenuate the mobilization of trace contaminants by coprecipitation or adsorption (Harrison et al, 2017;Pearce et al, 2018). In addition to iron secondary precipitates, barite and gypsum have been recognized to form due to chemical alteration of shale, which can decrease shale permeability (Li et al, 2019;Li et al, 2020).…”

Section: Introductionmentioning

confidence: 99%

Effect of salinity on the kinetics of pyrite dissolution in oxygenated fluids at 60 °C and implications for hydraulic fracturing

Vandeginste

Siska

Belshaw

et al. 2021

Journal of Natural Gas Science and Engineering

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Experimental and predicted geochemical shale-water reactions: Roseneath and Murteree shales of the Cooper Basin

Cited by 41 publications

References 26 publications

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

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

Identification of Geochemical Processes During Hydraulic Fracturing of a Shale Gas Reservoir: A Controlled Field and Laboratory Water‐Rock Interaction Experiment

Effect of salinity on the kinetics of pyrite dissolution in oxygenated fluids at 60 °C and implications for hydraulic fracturing

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