Integrative Understanding of Shale Gas Reservoirs

Lee, Kun Sang; Kim, Tae Hong

doi:10.1007/978-3-319-29296-0

Cited by 33 publications

(25 citation statements)

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“…While studying K and n parameters individually, it was found that parameter k is a quadratic function of dimensionless concentration, as shown in Equation (4). Meanwhile, the parameter n is related to dimensionless concentration through a linear equation as shown in Equation (5). Figure 4 presents the matches between observed and predicted values and an acceptable trend was noticed.…”

Section: Concentration (Ppm)supporting

confidence: 52%

“…These huge reserves are unlocked by fracturing shales [5]. When the shales are fractured using conventional aqueous based polymer solutions, the plugging of nanopores takes place [6][7][8][9][10][11].…”

Section: Introductionmentioning

confidence: 99%

“…In addition, the expansion of gas phase after treatment helps to recover the introduced liquid phase into the formation. CO 2 gas is more beneficial due to relatively high adsorption ability as compared to CH 4 , which is a good aspect for releasing the adsorbed gas and underground carbon sequestration [5,9,[12][13][14][15][16][17].…”

Section: Introductionmentioning

confidence: 99%

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Viscosity Models for Polymer Free CO2 Foam Fracturing Fluid with the Effect of Surfactant Concentration, Salinity and Shear Rate

et al. 2017

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High quality polymer free CO 2 foam possesses unique properties that make it an ideal fluid for fracturing unconventional shales. In this paper, the viscosity of polymer free fracturing foam and its empirical correlations at high pressure high temperature (HPHT) as a function of surfactant concentration, salinity, and shear rate are presented. Foams were generated using a widely-used surfactant, i.e., alpha olefin sulfonate (AOS) in the presence of brine and a stabilizer at HPHT. Pressurize foam rheometer was used to find out the viscosity of CO 2 foams at different surfactant concentration (0.25-1 wt %) and salinity (0.5-8 wt %) over a wide range of shear rate (10-500 s −1 ) at 1500 psi and 80 • C. Experimental results concluded that foam apparent viscosity increases noticeably until the surfactant concentration of 0.5 wt %, whereas, the increment in salinity provided a continuous increase in foam apparent viscosity. Nonlinear regression was performed on experimental data and empirical correlations were developed. Power law model for foam viscosity was modified to accommodate for the effect of shear rate, surfactant concentration, and salinity. Power law indices (K and n) were found to be a strong function of surfactant concentration and salinity. The new correlations accurately predict the foam apparent viscosity under various stimulation scenarios and these can be used for fracture simulation modeling.

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Section: Concentration (Ppm)supporting

confidence: 52%

Section: Introductionmentioning

confidence: 99%

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Viscosity Models for Polymer Free CO2 Foam Fracturing Fluid with the Effect of Surfactant Concentration, Salinity and Shear Rate

et al. 2017

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“…Shales, as unconventional reservoirs, possess significant amounts of stored reserves that have drawn great attention. Hydraulic fracturing of shales is a technique that is widely known to unlock these stored reserves [3] and the fracturing fluids that are commonly used are polymer-based aqueous solutions. However, the application of polymers can plug the nanopores, which becomes a crucial issue [4][5][6][7][8][9].…”

Section: Introductionmentioning

confidence: 99%

Empirical Modeling of the Viscosity of Supercritical Carbon Dioxide Foam Fracturing Fluid under Different Downhole Conditions

et al. 2018

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High-quality supercritical CO 2 (sCO 2 ) foam as a fracturing fluid is considered ideal for fracturing shale gas reservoirs. The apparent viscosity of the fracturing fluid holds an important role and governs the efficiency of the fracturing process. In this study, the viscosity of sCO 2 foam and its empirical correlations are presented as a function of temperature, pressure, and shear rate. A series of experiments were performed to investigate the effect of temperature, pressure, and shear rate on the apparent viscosity of sCO 2 foam generated by a widely used mixed surfactant system. An advanced high pressure, high temperature (HPHT) foam rheometer was used to measure the apparent viscosity of the foam over a wide range of reservoir temperatures (40-120 • C), pressures (1000-2500 psi), and shear rates (10-500 s −1 ). A well-known power law model was modified to accommodate the individual and combined effect of temperature, pressure, and shear rate on the apparent viscosity of the foam. Flow indices of the power law were found to be a function of temperature, pressure, and shear rate. Nonlinear regression was also performed on the foam apparent viscosity data to develop these correlations. The newly developed correlations provide an accurate prediction of the foam's apparent viscosity under different fracturing conditions. These correlations can be helpful for evaluating foam-fracturing efficiency by incorporating them into a fracturing simulator.

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“…Furthermore, it is known that the Marcellus Shale is a naturally fractured reservoir. In general, shale gas reservoirs includes natural fractures which are believed to play a significant role in hydraulic fracture propagation and gas production (Lee & Kim, 2016). A naturally fractured reservoir has been referred to a dual porosity system because two types of porous regions that present distinctly different properties are in presence (Barenblatt et al, 1960).…”

Section: Introduction Of Parametric Studymentioning

confidence: 99%

Investigation of Gas Slippage Effect and Geomechanical Effect on Gas Production Prediction and Hydraulic Fracture Design -- A Case Study of Marcellus Shale

Rubin¹

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Shale reservoirs play an increasingly important role in energy supply worldwide. Horizontal wells and hydraulic fracturing have created a new mandate for a better understanding of the resulted production amounts from these shale reservoirs. A parametric study, based on Marcellus shale laboratory Precision Petrophysical Analysis Laboratory (PPAL) experimental data, and reservoir simulation is conducted to understand the effects of gas slippage effect and the geomechanical effects on gas production prediction and completion design. Therefore by analyzing the critical conductivity of a reservoir prior to production it is possible to design a fracture treatment (i.e. proppant pumping strategy) which will have positive impacts on the well performance and increased ROFI (Return on Fracturing Investment). The study is conducted for three shale reservoir scenarios; non-naturally fractured reservoir, low permeable naturally fractured reservoir, and high permeable naturally fractured reservoir. In this study, we perform a comprehensive parametric study by running reservoir simulations using empirical permeability correlations developed by means of steady-state permeability data obtained under varying stress and pore pressure conditions. The full correlation incorporates both the gas slippage effect and the geomechanic effect. The contrast correlations consider either one of the effects or no effects at all. A simulation of the fluid flow in the hydraulic fracture and matrix are performed by a three-dimensional finite-difference based reservoir model. The primary and natural fractures are modeled explicitly as discrete grid blocks. Additionally, we study the impact of the two matrix permeability effects on the critical conductivity results for different bottomhole pressures, propped fracture lengths, and fracture half spacings. A similar study is also performed for the naturally fractured shale reservoir scenario. The impacts of the slippage effect (matrix) and the geomechanical effects (matrix & natural fracture) are investigated in the same way. Furthermore, an analysis of the geomechanical effect in just the natural fractures is performed, and finally an economic analysis based on the overlying trends from the study is implemented. The following are key results found throughout the study. First, the gas slippage effect (matrix) appears to play a significant role at lower pore pressures below 1000 psi, and the geomechanical effect (matrix) is significant throughout all pressure levels (250-4500 psi) for the Marcellus Shale sample. Since most production pressure never goes below 1000 psi, it is apparent that the pore pressure effect is negligible. For the production prediction study the following results were determined for all three reservoir types (non-naturally fractured reservoir, low permeable naturally fractured reservoir, and high permeable naturally fractured reservoir). If the geomechanical effect (matrix) is ignored than production will be overestimated 2.3 to 14% from 1 to 20 years. If the pore pressure effect (...

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Integrative Understanding of Shale Gas Reservoirs

Cited by 33 publications

References 0 publications

Viscosity Models for Polymer Free CO2 Foam Fracturing Fluid with the Effect of Surfactant Concentration, Salinity and Shear Rate

Viscosity Models for Polymer Free CO2 Foam Fracturing Fluid with the Effect of Surfactant Concentration, Salinity and Shear Rate

Empirical Modeling of the Viscosity of Supercritical Carbon Dioxide Foam Fracturing Fluid under Different Downhole Conditions

Investigation of Gas Slippage Effect and Geomechanical Effect on Gas Production Prediction and Hydraulic Fracture Design -- A Case Study of Marcellus Shale

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