Exploration and Drilling in Shale Gas and Oil Reserves

Zendehboudi, Sohrab; Bahadori, Alireza

doi:10.1016/b978-0-12-802100-2.00003-4

Cited by 4 publications

(3 citation statements)

References 6 publications

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“…In the last two decades, the reservoir fracking activity has turned to the rates of oil production of unconventional reservoirs worldwide. The reservoir fracking occurs by inducing high pressure into the reservoir formation until the sum of the in situ stresses are exceeded . As a result of the exceeded pressure, multiple complex fracture networks within the reservoir formation are created, often called the stimulated reservoir volume (SRV).…”

Section: Introductionmentioning

confidence: 99%

“…The reservoir fracking occurs by inducing high pressure into the reservoir formation until the sum of the in situ stresses are exceeded. 1 As a result of the exceeded pressure, multiple complex fracture networks within the reservoir formation are created, often called the stimulated reservoir volume (SRV). Consequently, it improves the absolute permeability of the reservoir, leading to enhanced oil recovery (EOR) rates and an increased net-present-value (NPV) of the project.…”

Section: Introductionmentioning

confidence: 99%

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Catalytic Activation of Ammonium Nitrate and Sodium Nitrite: Experimental, Modeling and Prediction of the Fracking Envelope in Low-Permeability Reservoirs with Light and Heavy Oils

Rojas,

Rezaei Koochi,

Varfolomeev

et al. 2023

Energy Fuels

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The catalytic activation of thermochemical fluids or binary mixtures (BMs) based on ammonium nitrate and sodium nitrite was experimentally and numerically investigated as well as kinetically modeled. Experimental evidence in an autoclave reactor indicated an increase of temperature up to 242.5 °C and pressure up to 47.7 bar after the catalytic activation under standard conditions is accomplished. By means of the T and P growth and the observed reaction products (N2, NO2, and H2O), the reaction kinetic constants along with its stoichiometry were established and later on validated with a numerical reactor model. Subsequently, field-scale numerical models evaluated the activation of the BM within different reservoir rock quality (porosity: 3–15% and permeability: 4.4–111 mD), fluid type (light and heavy oils), injection rate (1–3 m3), and initial reservoir pressure (85 and 150 bar). Poor reservoir quality and injection rate were observed as the dominant requirements to ensure a more aggressive reservoir fracking. They illustrated an exponential response on the peak pressure, particularly at porosity and permeability values <5% and <17 mD, respectively. The exhibited peak pressures in our models range from 108–389 to 144–392 bar, for the light and heavy oils, respectively. We found that these in situ pressures are substantially in excess in reference to the predicted fracking pressure of the studied reservoirs. This implies that the activation of the BM within the porous media is a promising reservoir fracking method. Moreover, its robust exothermicity surpasses the reported glass transition and melting temperature of certain asphaltenes. Our findings can provide meaningful understanding about the geologyinjection requirements that can lead to fracking a given reservoir as well as its thermal development potential for well cleaning purposes when implementing BM for IOR applications.

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Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Catalytic Activation of Ammonium Nitrate and Sodium Nitrite: Experimental, Modeling and Prediction of the Fracking Envelope in Low-Permeability Reservoirs with Light and Heavy Oils

Rojas,

Rezaei Koochi,

Varfolomeev

et al. 2023

Energy Fuels

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“…Quartz sand, Resin Coated Sand, Ceramic Proppants, and High Strength Proppants are used as proppants [8][9][10][11]. An ideal proppant material should have the following characteristics: have adequate uniaxial compressive strength, do not deform, be chemically inert to the fracturing fluid containing various chemical compounds, have a low density, be easily accessible and cheap, prevent flowback, and not be pressed into the rock (embedment) [12,13].…”

Section: Introductionmentioning

confidence: 99%

Laboratory Testing of Fracture Conductivity Damage by Foam-Based Fracturing Fluids in Low Permeability Tight Gas Formations

2021

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In the case of fracturing of the reservoirs using fracturing fluids, the size of damage to the proppant conductivity caused by treatment fluids is significant, which greatly influence the effective execution of hydraulic fracturing operations. The fracturing fluid should be characterized by the minimum damage to the conductivity of a fracture filled with proppant. A laboratory research procedure has been developed to study the damage effect caused by foamed and non-foamed fracturing fluids in the fractures filled with proppant material. The paper discusses the results for high quality foamed guar-based linear gels, which is an innovative aspect of the work compared to the non-foamed frac described in most of the studies and simulations. The tests were performed for the fracturing fluid based on a linear polymer (HPG—hydroxypropyl guar, in liquid and powder form). The rheology of nitrogen foamed-based fracturing fluids (FF) with a quality of 70% was investigated. The quartz sand and ceramic light proppant LCP proppant was placed between two Ohio sandstone rock slabs and subjected to a given compressive stress of 4000–6000 psi, at a temperature of 60 °C for 5 h. A significant reduction in damage to the quartz proppant was observed for the foamed fluid compared to that damaged by the 7.5 L/m3 natural polymer-based non-foamed linear fluid. The damage was 72.3% for the non-foamed fluid and 31.5% for the 70% foamed fluid, which are superior to the guar gum non-foamed fracturing fluid system. For tests based on a polymer concentration of 4.88 g/L, the damage to the fracture conductivity by the non-foamed fluid was 64.8%, and 26.3% for the foamed fluid. These results lead to the conclusion that foamed fluids could damage the fracture filled with proppant much less during hydraulic fracturing treatment. At the same time, when using foamed fluids, the viscosity coefficient increases a few times compared to the use of non-foamed fluids, which is necessary for proppant carrying capacities and properly conducted stimulation treatment. The research results can be beneficial for optimizing the type and performance of fracturing fluid for hydraulic fracturing in tight gas formations.

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