Multiscale Characterization of the Caney Shale — An Emerging Play in Oklahoma

Wang, Yulun; Luo, Guofan; Achang, Mercy; Cains, Julie M.; Wethington, Conn; Katende, Allan; Grammer, G. Michael; Puckette, Jim; Pashin, Jack C.; Castagna, Marc; Chan, Han; King, George E.; Radonjic, Mileva

doi:10.17161/mg.v2i.15911

Cited by 12 publications

(8 citation statements)

References 40 publications

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“…The Caney Shale is a largely unexploited but potentially economically viable unconventional petroleum formation found within the South-Central Oklahoma Oil Province (SCOOP). − This formation was regarded a source and seal formation, accounting for its present relatively unexploited status. ,,, The target for drilling in the area in the past has been the Woodford Shale, which directly underlies the Caney Shale. Though the Caney Shale is replete with recoverable hydrocarbon resources, research and exploration activity undertaken on this formation is limited.…”

Section: Introductionmentioning

confidence: 99%

Integrated Experimental and Modeling Study of Geochemical Reactions of Simple Fracturing Fluids with Caney Shale

et al. 2022

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Interactions between rock minerals and hydraulic fracturing fluids directly impact the geochemical and geomechanical properties of shale formations. However, the mechanisms of geochemical reactions in shale unconventional reservoirs remain poorly understood. To investigate the geochemical reactions between shale and hydraulic fracturing fluids, a series of batch reactor experiments were undertaken. Three rock samples with different mineralogical compositions and three fluid samples of different compositions [deionized water, deionized water + 2% potassium chloride (KCl), and deionized water + 0.5% choline chloride (C5H14ClNO)] were used. Experiments were undertaken at reservoir temperature and atmospheric pressure. Elemental compositions of effluents after 1, 3, 7, 14, and 28 days were analyzed using inductively coupled plasma mass spectrometry. Medical computed tomography scanning and X-ray fluorescence spectroscopy were conducted on the entire core to help upscale results obtained from rock–fluid interaction experiments. Geochemical modeling using a reactive simulator, TOUGHREACT, was undertaken to corroborate experimental results. Results show that a lower pH triggered high dissolution rates in the rock samples, especially the carbonate components. As the pH increased, the rate of dissolution declined significantly, though for most cases dissolution still continued. The observed dissolved silica concentrations were much higher than the quartz solubility, suggesting that much of the silica originated from more soluble silica polymorphs and possibly desorption from clay mineral exchange sites. The concentration of most elemental species in solution increased, but aluminum (Al) and magnesium (Mg) concentrations declined rapidly following initial entry into solution. Geochemical modeling corroborated the conclusions regarding mineral dissolution and precipitation observed from experiments, notably the dissolution of calcite and pyrite in the reacted shale samples, the likely presence of silica polymorphs such as opal, chalcedony, or amorphous silica in these samples, and the reduction of Al and Mg concentrations in solution by precipitation of secondary aluminosilicate phases. The de-flocculation of clay minerals during reaction implies fines migration after hydraulic fracturing. This is detrimental to reservoir productivity as clay fines are displaced and lodged within the micro- and nanofractures created during fracturing. The immediate consumption of Al and Mg also has implications on blockage of hydrocarbon pathways due to precipitation of new minerals in these locations.

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Section: Introductionmentioning

confidence: 99%

Integrated Experimental and Modeling Study of Geochemical Reactions of Simple Fracturing Fluids with Caney Shale

et al. 2022

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“…This well is located within the Ardmore Basin of Southern Oklahoma, one of the basins traversed by the Caney Shale (Paronish et al 2020). The well was drilled across ve (5) zones designated as reservoir and ductile formations within the Caney Shale (Radonjic et al 2020;Wang et al 2021). The samples were collected as core-plugs at selected depths of each zone, mainly from a 4-inch recovered cored rock.…”

Section: Methodsmentioning

confidence: 99%

Mineral and Fluid Transformation of Hydraulically Fractured Shale: Case Study of Caney Shale in Southern Oklahoma

Awejori,

Dong,

Doughty

et al. 2024

Preprint

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This study explores the geochemical causes of permeability loss in hydraulically fractured reservoirs. The experiments involved the reaction of powdered-rock samples with produced brines in batch reactor system at temperature of 95oC and atmospheric pressure for 7-days and 30-days respectively. Results show changes in mineralogy and chemistry of rock and fluid samples respectively, therefore confirming chemical reactions between the two during the experimental period. The shift in mineralogy of the rock included decreases of pyrite, feldspar, and carbonate content whiles illite content showed an initial increase before decreasing. Results from analyses of post-reaction fluids generally corroborate the results obtained for mineralogical analyses. In essence, the results reveal a complex trend of reactions between rock and fluid samples which is summarized as follows. Breakdown and oxidation of pyrite by oxygenated fluid causes transient and localized acidity which triggers the dissolution of feldspar, carbonates, and other minerals susceptible to dissolution under acidic conditions. The dissolution of minerals releases high concentrations of ions which subsequently precipitate secondary minerals. On the field scale, the formation of secondary minerals in the pores and flow paths of hydrocarbons significantly reduces the permeability of the reservoir, which culminates in rapid productivity decline. This study provides an understanding of the geochemical rock-fluid reactions that impact long term permeability of shale reservoirs. Findings from the study also reveal the potential of depleted hydraulically fractured shale reservoirs as carbon storage units.

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“…The Late Mississippian Caney Shale (mostly Chesterian) is widely found in the Admore Basin and neighboring Anadarko, Marietta, and Arkoma Basins in southern Oklahoma (Figure ). The organic-rich (TOC, 0.5%–11.0%) and calcareous Caney Shale also consists of abundant clay-rich (mainly illite and mixed illite/smectite) and silt quartz-rich layers, with a thermal maturity of oil window. ,, …”

Section: Sample and Methodologymentioning

confidence: 99%

“…The organic-rich (TOC, 0.5%−11.0%) and calcareous Caney Shale also consists of abundant clay-rich (mainly illite and mixed illite/smectite) and silt quartz-rich layers, with a thermal maturity of oil window. 21,61,62 2.2. Sample.…”

Section: Sample and Methodologymentioning

confidence: 99%

“…Shale is a complicated geomaterial, composed of a wide range of organic macerals (e.g., type I, II, and III kerogen, bitumen, and pyrobitumen), minerals (e.g., typically, quartz, feldspar, calcite, dolomite, pyrite, and clay minerals), and pore sizes (<1 nm to 1 μm, over 3 orders of magnitude). ,− ,− All the factors result in the heterogeneous nature of shale that is complicated further by subsequent diagenesis after sedimentation and render difficulties in an accurate estimation of subsurface shale gas. ,− ,− Within a shale matrix, OM and clay minerals are regarded as functional minerals to adsorbed gas due to well-developed micropores (<2 nm) and mesopores (2–50 nm), which provide significant pore volume (PV) and specific surface area (SSA) for subsurface adsorption. ,, The type, enrichment, and thermal maturity of OM were abundantly reported to impact adsorption capacity in the past decade. ,, Total organic carbon (TOC) content was observed positively correlated to methane adsorption capacity and total gas content . Microporosity associated with OM and clay minerals was also suggested contributing to a high capacity of methane adsorption .…”

Section: Introductionmentioning

confidence: 99%

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Insights into Controls of Mineralogy and Pore Structure on the Density of Methane Adsorption Phase in Shales under Supercritical Conditions

2022

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With gradually increasing enhancing population and industrialization, exploitation of shale gas is enhancing in the world to satisfy the growing demand for energy worldwide. To exploit shale gas efficiently, accurate assessment of shale gas in place (GIP) is necessary for determining production strategies. Unlike free and dissolved gas, adsorbed gas contributes to the shale GIP up to 85% due to the well-developed surface area and micropores. Measured excess adsorption of methane (up to over 95% of subsurface shale gas) is often corrected to absolute adsorption to obtain the actual amount of adsorption under supercritical (or geological) conditions. During the correction, adsorption phase density (APD) is critical. However, the APD of subsurface shale gas and the effects of shale properties (e.g., mineralogy and pore structure) on APD remain poorly understood. A series of high-pressure methane adsorption isotherms (HPMAI) on Caney Shales were collected and analyzed in conjunction with other United States and Chinese shales from the literature at 35–125 °C and up to 15 MPa. A three-layer Ono–Kondo (OK3) model is utilized to derive the temperature- and pressure-dependent APD coupling low-pressure nitrogen adsorption isotherms (LPNAI) and HPMAI. X-ray diffraction and organic geochemistry are combined to reveal the mineralogy. Brunauer–Emmett–Teller, Barrett–Joyner–Halenda, and Horvath–Kawazoe analyses via LPNAI are used to investigate the pore structures. Results show that APD increases with organic matter (OM) proxied by total organic carbon and decreases with clay minerals and the sum of quartz and feldspar. OM dramatically contributes to the APD as multiple-layer adsorption exists, and the APD for OM could be 1.4–8.5 times that for clay minerals. Other inorganic minerals contribute less to APD. The properties and constitution of the surface area instead of the volume fraction contribute to the APD in shales. APD does not show an obvious correlation with micropore volume, likely related to the ratio of micropore volume to the total pore volume. This work provides a significant and comprehensive study of petrological factors that impact the APD of subsurface shale gas, which will improve the estimation of supercritical adsorption and shale GIP under reservoir conditions. Also, the findings in this work can provide applications for subsurface carbon dioxide adsorption and storage.

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Multiscale Characterization of the Caney Shale — An Emerging Play in Oklahoma

Cited by 12 publications

References 40 publications

Integrated Experimental and Modeling Study of Geochemical Reactions of Simple Fracturing Fluids with Caney Shale

Integrated Experimental and Modeling Study of Geochemical Reactions of Simple Fracturing Fluids with Caney Shale

Mineral and Fluid Transformation of Hydraulically Fractured Shale: Case Study of Caney Shale in Southern Oklahoma

Insights into Controls of Mineralogy and Pore Structure on the Density of Methane Adsorption Phase in Shales under Supercritical Conditions

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