A Material Balance Equation for Stress-Sensitive Shale Gas Condensate Reservoirs

Orozco, Daniel; Aguilera, Roberto F.

doi:10.2118/177260-ms

Cited by 4 publications

(3 citation statements)

References 20 publications

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“…The storage mechanisms in shale reservoirs were concluded, and the gas shale was viewed as a quintuple porosity system: free gas in inorganic pore, free gas in organic pore, free gas in fracture, adsorbed gas in kerogen, and dissolved gas in the kerogen or bitumen (Orozco and Aguilera, 2015). Given the similarity between kerogen and bitumen underground, methane dissolved in solid kerogen underground is the same as in bitumen (Swami et al, 2013).…”

Section: Gas Storage In Shale With Different Maturitymentioning

confidence: 99%

“…A similar material balance equation was created, in which the gas stored in natural fracture can be essential (Duarte et al, 2014;Radan et al, 2017). A material balance equation was also constructed for gas condensate instead of dry gas in shale reservoir (Orozco and Aguilera, 2015). However, it is found in many basins that if the kerogen is overmature, the carbon in kerogen is recrystallizing to the mineral graphite, and the organic pore is like the coking observed in retorting of coals.…”

Section: Introductionmentioning

confidence: 99%

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Material Balance Equation of Overmature Organic-Rich Gas Shale

Yang¹

2018

Appl. Ecol. Env. Res.

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Abstract. Gas shale was treated as a quintuple porosity system. When the source rock matures, a portion of kerogen or bitumen will be transformed into hydrocarbon, and move to displace the water out from inorganic matrix. When the kerogen is recrystallized to graphite, there will be less dissolved gas left in solid kerogen, which was assumed to be substantial in immature source rock. A series of resistivity tests showed the resistivity of shale decreases with higher vitrinite reflectance value, and proved the graphite do exist in overmature shale. With the role of natural fracture in shale analyzed, the water and hydrocarbon stored in overmature shale was summarized, and the overmature organic-rich gas shale should be treated as two porosity system. To find out which kind of pore may accommodate most of the free gas, a generalized material balance equation was presented, and the volume change with pressure drop in organic matrix and inorganic matrix can be calculated simultaneously. The field case herein proved that new material balance equation can be applied to calculate original free gas and adsorbed gas in shale or sandstone, and it was suggested that while in overmature gas shale there is free gas in inorganic pore, free gas in organic pore and adsorbed gas in kerogen, most of the free gas is in the organic pores.

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Section: Gas Storage In Shale With Different Maturitymentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Material Balance Equation of Overmature Organic-Rich Gas Shale

Yang¹

2018

Appl. Ecol. Env. Res.

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“…The influences of adsorbed phase volume, dissolved gas, and free gas on fracture were not fully included in prior approaches for computing reserves of shale gas reservoirs, resulting in discrepancies in reserve calculation results. − The adsorption model and multiscale gas fluid flow are considered to describe the volume change of gas adsorption/desorption and gas dissolution. By rebuilding the pore volume model, the volume change of gas in kerogen, matrix, and fractures, the volume changes due to stress sensitivity and irreducible water expansion, and volume change due to adsorbed gas desorption are considered.…”

Section: Introductionmentioning

confidence: 99%

Modified Flowing Material Balance Equation for Shale Gas Reservoirs

Yang

Zhang

et al. 2022

ACS Omega

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To determine original gas-in-place, this study establishes a flowing material balance equation based on the improved material balance equation for shale gas reservoirs. The method considers the free gas in the matrix and fracture, the dissolved gas in kerogen, and the pore volume occupied by adsorbed phase simultaneously, overcoming the problem of incomplete consideration in the earlier models. It also integrates the material balance method with the flowing material balance method to obtain the average formation pressure, eliminating the problem with the previous method where shutting down of wells was needed to monitor the formation pressure. The volume of the adsorbed gas on the ground is converted into volume of the adsorbed phase in the formation using the volume conservation method to characterize the pore volume occupied by the adsorbed phase, which solves the problem of the previous model that the adsorbed phase was neglected in the pore volume. The model proposed in this study is applied to the Fuling Shale Gas Field in southwest China and compared with other flowing material balance equations, and the results show that the single-well control area calculated by the model proposed in this study is closer to the real value, indicating that the calculations in this study are more accurate. Furthermore, the calculations show that the dissolved gas takes up a large fraction of the total reserves and cannot be ignored. The sensitivity analyses of critical parameters demonstrate that (a) the greater the porosity of the fracture, the greater the free gas storage; (b) the values of Langmuir volume and TOC can significantly affect the results of the reservoir calculation; and (c) the adsorbed phase occupies a smaller pore volume when the Langmuir volume is smaller, the Langmuir pressure is higher, or the adsorbed phase density is higher. The findings of this study can provide better understanding of the necessity to take into account the dissolved gas in the kerogen, the pore volume occupied by the adsorbed phase, and the fracture porosity when evaluating reserves. The method could be applied to the calculation of pressure, recovery of free gas phase and adsorbed phase, original gas-in-place, and production predictions, which could help for better guidance of reserve potential estimations and development strategies of shale gas reservoirs.

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Sorption-Dependent Permeability of Shales

Lopez

Aguilera

2015

Day 2 Wed, October 21, 2015

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Shale gas reservoirs are fine-grained, organic-rich rocks with a well-developed pore network structure within the organic matter (kerogen). Organic pores in shale reservoirs exhibit small radii in the range of 0.5 to 100 nanometers, which indicate that non-Darcy flow mechanisms are present in these rocks in addition to viscous flow. Gas adsorption/desorption and gas diffusion from solid kerogen are some other important flow mechanisms in shales. Therefore, consideration of these phenomena is crucial for quantification of permeability of shales. A numerical procedure to calculate permeability of shales that accounts for all the above factors is introduced in this work. During shale's depletion, organic pore radius can change or remain approximately constant depending on the rates of adsorption and desorption. Previous investigations suggest that organic pore radius increases as desorption takes place, which in turn also increases the space available for free gas and reduces the amount of adsorbed gas. This phenomenon thus increases shale permeability. This paper goes further and indicates that pore diameter can increase, decrease or remain approximately constant with time depending on the on-going desorption, adsorption and diffusion from solid kerogen. The effects on pore radius and permeability of all these mechanisms, viscous flow and Knudsen diffusion are addressed in this paper with the development of a ID radial simulation model. Two independent methods, which approximately corroborate each other, are presented for calculating changes in pore radius. Results show that considering pore radius changes due to sorption and diffusion have a significant impact on estimation of shale permeabilities. The effects on permeability vary under different reservoir conditions. The importance of solid kerogen as a gas source and its effect on gas flow is highlighted. The solid kerogen feeds organic pores affecting the rate of adsorption. Consequently the organic pore radius does not necessarily increase during production; it can decrease or even remain approximately constant. It is concluded that ignoring viscous flow, Knudsen diffusion and changes in pore radius lead to erroneous permeabilities. Gas diffusion from solid kerogen can be quite significant in shale reservoirs and should be taken into account. The main contribution of this paper is the development of a numerical method for calculating sorption- dependent permeability of shales. The calculations include Darcy and diffusive flows, and changes in organic pore radius due to adsorption/desorption and diffusion from solid kerogen. This is the first time all the aforementioned mechanisms are analyzed in a single study.

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A Material Balance Equation for Stress-Sensitive Shale Gas Condensate Reservoirs

Cited by 4 publications

References 20 publications

Material Balance Equation of Overmature Organic-Rich Gas Shale

Material Balance Equation of Overmature Organic-Rich Gas Shale

Modified Flowing Material Balance Equation for Shale Gas Reservoirs

Sorption-Dependent Permeability of Shales

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