Experimental evaluation of oxidation sensitivity in organic-rich shale reservoir

You, Lijun; Zhou, Yang; Kang, Yili; Cheng, Qiuyang; Zhang, Nan

doi:10.1016/j.petrol.2020.107230

Cited by 12 publications

(15 citation statements)

References 19 publications

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“…It can be seen from eq that the low initial water saturation ( S wi ) and the high capillary force ( P c ) are favorable geological conditions of shale gas formation for fluid imbibition. The clay content in shale is usually 21–80%. ,− The clay mineral can be divided into two categories: high specific surface area clay (smectite, I/S mixed-layer, etc.) and low specific surface clay (such as chlorite).…”

Section: Feasibility Of Zfr Of Hydraulic Fracturing Fluidmentioning

confidence: 99%

Zero Flowback Rate of Hydraulic Fracturing Fluid in Shale Gas Reservoirs: Concept, Feasibility, and Significance

et al. 2021

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A high flowback rate of hydraulic fracturing fluid (HFF) yields a high gas production rate in a tight sand gas reservoir. This idea is well followed when it comes to the hydraulic fracturing of a shale gas well. Therefore, numerous studies have focused on increasing the flowback rate of HFF in shale gas reservoirs to mitigate the water blocking damage. Yet, only a small portion of the injected fluid (less than 20%) could be recovered during flowback operation. Moreover, there is no good correlation between the gas production rate and flowback rate for shale gas wells. Surprisingly, a phenomenon that a low flowback rate of HFF usually yields a high gas production rate is found recently by field data studies. In this case, the authors investigated the reasons for this abnormal phenomenon and believed that reducing the flowback rate of HFF in a shale gas reservoir could be a new strategy for dealing with the injected HFF. Therefore, a new concept called zero flowback rate (ZFR) of HFF is put forward to serve as an unconventional way to manage the high volume of HFF. ZFR of HFF is a concept compared with the flowback rate of the fracturing fluid for a conventional reservoir. It is worth noting that zero in the ZFR concept does not stand for the absolute number 0. It means that reducing the flowback rate of HFF is the goal of the ZFR strategy. To analyze the feasibility of realizing ZFR, the geological conditions of gas shale and engineering conditions of hydraulic fracturing were evaluated by comparing the relative studies. It showed that gas shale has the potential to imbibe most of the HFF and retain the imbibed fluid without contaminating the groundwater. ZFR can be realized by extending the shut-in time or adjusting the properties of HFF. Compared with the conventional idea of increasing the flowback rate of HFF, ZFR is of great significance. It does not only recover the relative gas permeability of the shale reservoir by redistributing the liquid phase from the fractures into the shale matrix but also enhances it by creating new microfractures. ZFR is cost-saving and environmentally friendly by dealing with a reduced volume of flowback HFF. ZFR has a high potential of becoming a viable strategy for the development of shale gas reservoirs.

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Section: Feasibility Of Zfr Of Hydraulic Fracturing Fluidmentioning

confidence: 99%

Zero Flowback Rate of Hydraulic Fracturing Fluid in Shale Gas Reservoirs: Concept, Feasibility, and Significance

et al. 2021

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“…The reaction rates of calcite, pyrite, and barite reactions are calculated on the basis of the following equations: 49−51 • 6.9 H 0.22 7.9 barite (23) where R m is the reaction rate of mineral m, a i is the activity of the species i, and Ω m is the saturation ratio of the mineral m.…”

Section: Simulation Setupmentioning

confidence: 99%

“…Various studies have investigated the effects of the HFF–shale chemical interactions on the hydrodynamic properties of shale rocks (such as porosity and permeability) ,,− and the flowback water chemistry. ,,− Some of these studies have experimentally and numerically assessed the impact of HFF–shale chemical interactions on the alteration of the fracture–matrix interfaces at the pore scale (micrometer scale). ,, Although formation of this altered layer is a pore-scale feature, it can have large-scale impacts on hydrocarbon recovery because the thickness of this altered zone can influence the transport (advection and diffusion) of hydrocarbons from matrices to fractures in shale formations . A pore-scale parameter that controls the structure of this altered zone (or the reacted shale in general) is the pore-scale distribution of the matrix-forming minerals, especially the highly reactive phases, such as calcite.…”

Section: Introductionmentioning

confidence: 99%

Pore-Scale Modeling of Fluid–Rock Chemical Interactions in Shale during Hydraulic Fracturing

et al. 2021

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During the hydraulic fracturing process in unconventional shale gas reservoirs, chemical interactions between the hydraulic fracturing fluid (HFF) and the shale rock could result in mineral precipitation and dissolution reactions, potentially influencing the gas transport by dissolving or clogging the fractures. The pore-scale distribution of the minerals, especially the highly reactive minerals, such as calcite, in the shale matrix can impact the structural evolution of the shale rocks. In the present study, a pore-scale reactive transport model is built to investigate the impact of the pore-scale distribution of calcite on the structural alteration of the shales. The alteration of the shales is caused by the barite precipitation and the dissolution of calcite and pyrite. The simulation results show that the calcite dissolution leads to a permeability enhancement. The permeability enhancement for the shales with coarser calcite grains is more pronounced than that for the shales with finer grains of calcite. The results also indicate that the extent of the permeability enhancement is even more noticeable if the HFF is injected with a higher velocity. The fluid chemistry analysis indicates that the fluid pH for the shale with the fine grains of calcite is higher than that of the shale with the coarse calcite grains and that the injection of the HFF with a higher flow rate leads to the lower pH values. The calcite dissolution observed in the simulations mainly occurs near the inlet. For the shale with the finer calcite grains, barite precipitation occurs mostly close to the inlet, but for the shale with coarser calcite grains, barite precipitation extends more into the domain. This penetration depth increases when the HFF is injected with a higher velocity. In addition to the effect of the calcite distribution, we also used the pore-scale model to study the effect of the calcite content on the structural evolution of the shales. The results from these simulations showed that a higher calcite content can result in higher pH values, higher permeabilities, and more barite precipitation in the domain.

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“… 5 However, You reported that the oxidation of pyrite could produce dissolution pores and cracks, and the oxidation sensitivity was controlled by the pyrite content, dissolved oxygen content, and reservoir conditions. 23 Moreover, Li revealed that the pyrite oxidation zone was >0.5 cm into the shale matrix during hydraulic fracturing via synchrotron X-ray-based techniques, indicating that the pyrite oxidation occurred not only close to microfractures but also in a wider range of shale reservoir matrix. 24 Owing to the complex mineral composition in organic-rich shale, the mechanism of the pore structure change induced by pyrite oxidation is still not well-understood.…”

Section: Introductionmentioning

confidence: 99%

Impact of Pyrite Oxidation on the Pore-Structure Characteristics of Shale Reservoir Rocks under the Interaction of Fracturing Fluid

Sun

et al. 2022

ACS Omega

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Hydraulic fracturing combined with horizontal drilling is widely used to develop shale gas resources, and huge amounts of fracturing fluid are injected into shale reservoirs. However, the fracturing fluid is ineluctably retained in reservoir rocks after fracturing, resulting in the alteration of shale pore systems and further affecting the hydrocarbons production efficiency. In this work, two types of shales with different pyrite contents, namely, pyrite rich (PR, Niutitang Formation) and pyrite poor (PP, Xiamaling Formation), were emphasized to illustrate the effect of pyrite oxidation on pore structure after fracturing operation. Slickwater fracturing fluid was used to treat the shale samples for a period of 3 days, under the condition of 100 °C and 50 MPa. The field emission scanning electron microscopy (FE-SEM) and X-ray diffraction (XRD) were utilized to determine the surface morphology and mineral composition. The low-temperature N 2 adsorption was performed to quantify the pore structure. The results showed that the pyrite oxidation induced the dissolution of both the pyrite and calcite and generated many dissolution pores for the pyrite-rich shale after slickwater treatment. The mineral dissolution led to an increase in the number of mesopores, enlarged the total specific surface area (TSSA) and total pore volume (TPV), and strengthened the pore-structure complexity. On the other hand, the pyrite-poor shale only experienced clay swelling after slickwater treatment. Its pore surface roughness and pore-structure complexity degraded with the loss of nanopores and the reductions in TSSA and TPV. The results of this study enhance the understanding of the impact of pyrite oxidation on the pore structure and provide new insight into the optimization of fracturing operation conditions based on shale’s mineral composition characteristics.

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Experimental evaluation of oxidation sensitivity in organic-rich shale reservoir

Cited by 12 publications

References 19 publications

Zero Flowback Rate of Hydraulic Fracturing Fluid in Shale Gas Reservoirs: Concept, Feasibility, and Significance

Zero Flowback Rate of Hydraulic Fracturing Fluid in Shale Gas Reservoirs: Concept, Feasibility, and Significance

Pore-Scale Modeling of Fluid–Rock Chemical Interactions in Shale during Hydraulic Fracturing

Impact of Pyrite Oxidation on the Pore-Structure Characteristics of Shale Reservoir Rocks under the Interaction of Fracturing Fluid

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