Feldspar dissolution-enhanced porosity in Paleoproterozoic shale reservoir facies from the Barney Creek Formation (McArthur Basin, Australia)

Baruch, Elizabeth; Kennedy, Martin J.; Löhr, Stefan; Dewhurst, David N.

doi:10.1306/04061514181

Cited by 76 publications

(33 citation statements)

References 61 publications

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“…With the generation of hydrocarbons, many micropores will be generated inside the organic matter, and the micropores will provide a large specific surface area (Modica and Lapierre 2012;Milliken et al 2013). Organic acids formed during the early maturity of organic matter can dissolve feldspar minerals and form considerable dissolution pores (Baruch et al 2015). Oil and asphalt fillings can block pores in "oil windows" (Mastalerz et al 2013).…”

Section: Edited By Jie Haomentioning

confidence: 99%

Porosity model and pore evolution of transitional shales: an example from the Southern North China Basin

Yang

Guo

2020

Pet. Sci.

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The evolution of shale reservoirs is mainly related to two functions: mechanical compaction controlled by ground stress and chemical compaction controlled by thermal effect. Thermal simulation experiments were conducted to simulate the chemical compaction of marine-continental transitional shale, and X-ray diffraction (XRD), CO 2 adsorption, N 2 adsorption and high-pressure mercury injection (MIP) were then used to characterize shale diagenesis and porosity. Moreover, simulations of mechanical compaction adhering to mathematical models were performed, and a shale compaction model was proposed considering clay content and kaolinite proportions. The advantage of this model is that the change in shale compressibility, which is caused by the transformation of clay minerals during thermal evolution, may be considered. The combination of the thermal simulation and compaction model may depict the interactions between chemical and mechanical compaction. Such interactions may then express the pore evolution of shale in actual conditions of formation. Accordingly, the obtained results demonstrated that shales having low kaolinite possess higher porosity at the same burial depth and clay mineral content, proving that other clay minerals such as illite-smectite mixed layers (I/S) and illite are conducive to the development of pores. Shales possessing a high clay mineral content have a higher porosity in shallow layers (< 3500 m) and a lower porosity in deep layers (> 3500 m). Both the amount and location of the increase in porosity differ at different geothermal gradients. High geothermal gradients favor the preservation of high porosity in shale at an appropriate R o. The pore evolution of the marine-continental transitional shale is divided into five stages. Stage 2 possesses an R o of 1.0%-1.6% and has high porosity along with a high specific surface area. Stage 3 has an R o of 1.6%-2.0% and contains a higher porosity with a low specific surface area. Finally, Stage 4 has an R o of 2.0%-2.9% with a low porosity and high specific surface area.

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Section: Edited By Jie Haomentioning

confidence: 99%

Porosity model and pore evolution of transitional shales: an example from the Southern North China Basin

Yang

Guo

2020

Pet. Sci.

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“…Kerogen pyrolysis, liquid hydrocarbon and bitumen cracking, and volatile matter release generate nearly circular or bubble-like pores in OM [54,55] and gaseous hydrocarbon generation forms high pore pressure resisting further compaction [56,57], while OM shrinkage forms fissures [58]. Organic acids originating from kerogen decarboxylation, hydrocarbon cracking, and minerals oxidation dissolve feldspar and clay mineral to form secondary pores [59,60]. Illitization of kaolinite dissolves feldspar [61,62], while the Fe 3+ from the conversion of smectite to illite in I/S promotes the release of the peripheral dicarboxylic acid group from kerogen and improves the formation of carboxylic acids and phenols [63], which contribute to the development of secondary dissolved pores.…”

Section: Pore Evolutionmentioning

confidence: 99%

Upper Paleozoic Transitional Shale Gas Enrichment Factors: A Case Study of Typical Areas in China

Wang

Guo

2020

Minerals

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Based on the shale gas research experience in North America, large-scale geological evaluations have been conducted in China to determine the enrichment characteristics of deep marine shale gas, leading to the discovery of the Fuling, Changning and Weiyuan shale gas fields. However, research on Upper Paleozoic transitional shale gas remains limited, restricting the subsequent exploration and development. Therefore, taking the Lower Permian Shanxi and Pennsylvanian Taiyuan Formations in the northeastern Ordos Basin and the Upper Permian Longtan Formation in southwestern Guizhou as examples, gas logging, gas desorption, thermal simulation, maximum vitrinite reflectance (Rmax), and X-ray diffraction (XRD) were used to study the influence of lithological associations, sedimentary facies, gas generation thresholds, and pore evolution on transitional shale gas, and then Upper Paleozoic transitional shale gas enrichment factors of the northeastern Ordos Basin and southwestern Guizhou were analysed. The results show that carbonaceous mudstone adjacent to coal seams presents a high gas content level, and is primarily developed in swamps in the delta plain environment, and swamps and lagoons in the barrier coastal environment. The gas generation threshold maturity (Rmax) of transitional shale is 1.6% and the corresponding threshold depths of the northeastern Ordos Basin and southwestern Guizhou are estimated to be 2265 m and 1050 m. Transitional shale pore evolution is jointly controlled by hydrocarbon generation, clay minerals transformation, and compaction, and may have the tendency to decrease when Rmax < 1.6% or Rmax > 3.0%, but increase when Rmax ranges between 1.6% and 3.0%, while the main influential factors of pore evolution differ in each period. Continuous distribution of transitional shale gas enrichment areas can be formed along the slope adjacent to coal seams with a moderate maturity range (1.6%–3.0%) in the northeastern Ordos Basin, and transitional shale gas can be enriched in the areas adjacent to coal seams with a moderate maturity range (1.6%–3.0%), abundant fractures, and favorable sealing faults in southwestern Guizhou.

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“…For example, Heydari and Wade [45] point out that feldspar may react with water under temperatures of 80 to 120 • C and release ions and other minerals, which leads to the generation of dissolved pores. Besides, it is also reported that the dissolution of feldspar can increase the formation porosity and permeability [46]. During the field shut-in period, a large amount of hydraulic fracturing fluid with additives is trapped in the shale fracture networks.…”

Section: Effect Of Temperature On Hydrationmentioning

confidence: 99%

Effect of Shale Anisotropy on Hydration and Its Implications for Water Uptake

Zeng

Jin

et al. 2019

Energies

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Water uptake induced by fluid–rock interaction plays a significant role in the recovery of flowback water during hydraulic fracturing. However, the existing accounts fail to fully acknowledge the significance of shale anisotropy on water uptake typically under in situ reservoir temperature. Thus we investigated the shale-hydration anisotropy using two sets of shale samples from the Longmaxi Formation in Sichuan Basin, China, which are designated to imbibe water parallel and perpendicular to shale bedding planes. All the samples were immersed in distilled water for one to five days at 80 °C or 120 °C. Furthermore, samples’ topographical and elemental variations before and after hydration were quantified using energy-dispersive spectroscopy–field-emission scanning electron microscopy. Our results show that shale anisotropy and imbibition time strongly affect the width of pre-existing micro-fracture in hydrated samples. For imbibition parallel to lamination, the width of pre-existing micro-fracture initially decreases and leads to crack-healing. Subsequently, the crack surfaces slightly collapse and the micro-fracture width is enlarged. In contrast, imbibition perpendicular to lamination does not generate new micro-fracture. Our results imply that during the flowback process of hydraulic fracturing fluid, the shale permeability parallel to bedding planes likely decreases first then increases, thereby promoting the water uptake.

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Feldspar dissolution-enhanced porosity in Paleoproterozoic shale reservoir facies from the Barney Creek Formation (McArthur Basin, Australia)

Cited by 76 publications

References 61 publications

Porosity model and pore evolution of transitional shales: an example from the Southern North China Basin

Porosity model and pore evolution of transitional shales: an example from the Southern North China Basin

Upper Paleozoic Transitional Shale Gas Enrichment Factors: A Case Study of Typical Areas in China

Effect of Shale Anisotropy on Hydration and Its Implications for Water Uptake

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