Liquid Intake of Organic Shales

Dehghanpour, Hassan; Zubair, Hazairin; Chhabra, Abha; Ullah, Aman

doi:10.1021/ef3009794

Cited by 277 publications

(134 citation statements)

References 30 publications

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“…Fig. 1 illustrates the well as [10][11][12][13][14][15][16][17][18][19][20] hydrofractures that are H ∼ 30 m high and 2L ∼ 200 m long, spaced at distances of around 2d ∼ 100 m. The fact that this is the right starting point for these wells was recognized by Al-Ahmadi et al (9), and the diffusion problem in this setting has been studied by both Silin and Kneafsy (10), and Nobakht et al (11).…”

mentioning

confidence: 99%

Gas production in the Barnett Shale obeys a simple scaling theory

Patzek¹,

Columbu

Marder

2013

Proc. Natl. Acad. Sci. U.S.A.

328

258

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Natural gas from tight shale formations will provide the United States with a major source of energy over the next several decades. Estimates of gas production from these formations have mainly relied on formulas designed for wells with a different geometry. We consider the simplest model of gas production consistent with the basic physics and geometry of the extraction process. In principle, solutions of the model depend upon many parameters, but in practice and within a given gas field, all but two can be fixed at typical values, leading to a nonlinear diffusion problem we solve exactly with a scaling curve. The scaling curve production rate declines as 1 over the square root of time early on, and it later declines exponentially. This simple model provides a surprisingly accurate description of gas extraction from 8,294 wells in the United States' oldest shale play, the Barnett Shale. There is good agreement with the scaling theory for 2,057 horizontal wells in which production started to decline exponentially in less than 10 y. The remaining 6,237 horizontal wells in our analysis are too young for us to predict when exponential decline will set in, but the model can nevertheless be used to establish lower and upper bounds on well lifetime. Finally, we obtain upper and lower bounds on the gas that will be produced by the wells in our sample, individually and in total. The estimated ultimate recovery from our sample of 8,294 wells is between 10 and 20 trillion standard cubic feet.hydrofracturing | shale gas | scaling laws | energy resources | fracking T he fast progress of hydraulic fracturing technology (SI Text, Figs. S1 and S2) has led to the extraction of natural gas and oil from tens of thousands of wells drilled into mudrock (commonly called shale) formations. The wells are mainly in the United States, although there is significant potential on all continents (1). The "fracking" technology has generated considerable concern about environmental consequences (2, 3) and about whether hydrocarbon extraction from mudrocks will ultimately be profitable (4). The cumulative gas obtained from the hydrofractured horizontal wells and the profits to be made depend upon production rate. Because large-scale use of hydraulic fracturing in mudrocks is relatively new, data on the behavior of hydrofractured wells on the scale of 10 y or more are only now becoming available.There is more than a century of experience describing how petroleum and gas production declines over time for vertical wells. The vocabulary used to discuss this problem comes from a seminal paper by Arps (5), who discussed exponential, hyperbolic, harmonic, and geometric declines. Initially, these types of decline emerged as simple functions providing good fits to empirical data. Thirty-six years later, Fetkovich (6) showed how they arise from physical reasoning when liquid or gas flows radially inward from a large region to a vertical perforated tubing, where it is collected. For specialists in this area, the simplicity and familiarity of hyperbolic de...

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mentioning

confidence: 99%

Gas production in the Barnett Shale obeys a simple scaling theory

Patzek¹,

Columbu

Marder

2013

Proc. Natl. Acad. Sci. U.S.A.

328

258

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“…However, hydraulic fracturing triggers low recovery of fracturing fluids (usually <30% [4]), which raises concerns from both technical and environmental aspects. Several mechanisms have been proposed to understand why the fracturing fluids disappeared, e.g., remaining in fracture network [4,5], creating new fractures [6,7], hydration of clay minerals [8,9], capillary pressure [5][6][7]10], and osmotic flow [11,12].…”

Section: Introductionmentioning

confidence: 99%

Drivers of Wettability Alteration for Oil/Brine/Kaolinite System: Implications for Hydraulic Fracturing Fluids Uptake in Shale Rocks

et al. 2018

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Abstract:Hydraulic fracturing technique is of vital importance to effectively develop unconventional shale resources. However, the low recovery of hydraulic fracturing fluids appears to be the main challenge from both technical and environmental perspectives in the last decade. While capillary forces account for the low recovery of hydraulic fracturing fluids, the controlling factor(s) of contact angle, thus wettability, has yet to be clearly defined. We hypothesized that the interaction of oil/brine and brine/rock interfaces governs the wettability of system, which can be interpreted using Derjaguin-Landau-Verwey-Overbeek (DLVO) and surface complexation modelling. To test our hypothesis, we measured a suit of zeta potential of oil/brines and brine/minerals, and tested the effect of ion type (NaCl, MgCl 2 and CaCl 2 ) and concentrations (0.1, 1, and 5 wt %). Moreover, we calculated the disjoining pressure of the oil/brine/mineral systems and compared with geochemical modelling predictions. Our results show that cation type and salinity governed oil/brine/minerals wettability. Divalent cations (Ca 2+ and Mg 2+ ) compressed the electrical double layer, and electrostatically linked oil and clays, thus increasing the adhesion between oil and minerals, triggering an oil-wet system. Increasing salinity also compressed the double layer, and increased the site density of oppositely charged surface species which made oil and clay link more strongly. Our results suggest that increasing salinity and divalent cations concentration likely decrease water uptake in shale oil reservoirs, thus de-risking the hydraulic fracturing induced formation damage. Combining DLVO and surface complexation modelling can delineate the interaction of oil/brine/minerals, thus wettability. Therefore, the relative contribution of capillary forces with respect to water uptake into shale reservoirs, and the possible impairment of hydrocarbon production from conventional reservoirs can be quantified.

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“…The spontaneous imbibition is the dominant mechanism of the water transport into the formation because of the high capillary pressure by nanopores [17][18][19]. Recently studies have shown that the spontaneous imbibition of fracturing fluid can be a driving force to enhance the gas recovery for shale gas reservoir [20,21]. Thus, analysis of the spontaneous imbibition of shale and the potential effect on gas recovery needs urgent attention.…”

Section: Introductionmentioning

confidence: 99%

Mathematical Model for the Fluid-Gas Spontaneous Displacement in Nanoscale Porous Media considering the Slippage and Temperature

Liu

Lin

Cao

et al. 2018

Mathematical Problems in Engineering

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The fracturing fluid-gas spontaneous displacement during the fracturing process is important to investigate the shale gas production and formation damage. Temperature and slippage are the major mechanisms underlying fluid transport in the micro-/nanomatrix in shale, as reported in the previous studies. We built a fracturing fluid-gas spontaneous displacement model for the porous media with micro-/nanopores, considering two major mechanisms. Then, our spontaneous displacement model was verified by the experimental result of the typical shale samples and fracturing fluids. Finally, the influences of temperature, slip length, and pore size distribution on the spontaneous imbibition process were discussed. Slippage and temperature significantly influenced the imbibition process. Lower viscosity, higher temperature, and longer slip length increased the imbibition speed. Ignoring the temperature change and slippage will lead to significant underestimation of the imbibition process.

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Liquid Intake of Organic Shales

Cited by 277 publications

References 30 publications

Gas production in the Barnett Shale obeys a simple scaling theory

Gas production in the Barnett Shale obeys a simple scaling theory

Drivers of Wettability Alteration for Oil/Brine/Kaolinite System: Implications for Hydraulic Fracturing Fluids Uptake in Shale Rocks

Mathematical Model for the Fluid-Gas Spontaneous Displacement in Nanoscale Porous Media considering the Slippage and Temperature

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