Pore-throat radius and tortuosity estimation from formation resistivity data for tight-gas sandstone reservoirs

Ziarani, Ali S.; Aguilera, Roberto

doi:10.1016/j.jappgeo.2012.05.008

Cited by 77 publications

(23 citation statements)

References 20 publications

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“…What is more, the lower the permeability is, the higher degree the smaller throat will develop. Compared to the throat radius of Mesaverde sandstone calculated by theoretical equation (Ziarani and Aguilera 2012) and the throat radius of Canadian tight oil reservoirs obtained from N 2 adsorption (Ghanizadeh et al 2015), the throat radius is larger in tight oil reservoir of Ordos basin.…”

Section: Throat Size Distributionmentioning

confidence: 64%

Quantitative determination of pore and throat parameters in tight oil reservoir using constant rate mercury intrusion technique

Gao

Ling

2015

J Petrol Explor Prod Technol

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The development of tight oil depends on the characteristics of complicated pore throat parameters. In this study, the tight oil samples obtained from the Yanchang group of Ordos basin (China) are tested using the constant rate mercury intrusion technique to quantitatively determine the size of pore and throat parameters, as well as analyze the key parameters that control the quality of tight oil reservoir. The pore radius of sample analogously distributes in 100-200 lm and average pore radius varies from 103.7 to 139.74 lm. When the permeability is less than 1 9 10 -3 lm 2 , the throat peak radius and the average throat radius will be less than 1 lm; furthermore, the variation of throat distribution is in the range of 0.2-0.5 and 0.2-1.0 lm. On the contrary, if the permeability is greater than 1 9 10 -3 lm 2 , the average throat radius will be greater than 1 lm and the distribution range of throat will spread from 0.2-3.4 to 0.2-8.8 lm. As for the eleven samples, the main flow throat radius lies in the range of 0.41-3.71 lm, the throat quantity changes wildly from 1324 to 4271 number/cm 3 , the average pore throat ratio varies from 503.59 to 86.11, the pore mercury saturation alters in 17.65-55.95 % and the throat mercury saturation distributes in 13.44-27.6 %. It can be learned that there is no obvious difference in pore parameters for tight oil reservoir. Therefore, the difference of pore throat structure mainly existed in throat parameters, and the throat parameters are the key factors that affect the physical properties and recovery results.

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Section: Throat Size Distributionmentioning

confidence: 64%

Quantitative determination of pore and throat parameters in tight oil reservoir using constant rate mercury intrusion technique

Gao

Ling

2015

J Petrol Explor Prod Technol

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“…The measurements were carried out at a temperature of 16°C, a humidity of 50%. A mercury porosimeter is used to force mercury into all available space and measure entered mercury volume (Ziarani & Aguilera, 2012). Intrusion and extrusion curves as well as various key parameters were obtained, such as average pore-throat radius, maximum pore-throat radius, and maximum mercury intrusion saturation.…”

Section: Methodsmentioning

confidence: 99%

“…A mercury porosimeter is used to force mercury into all available space and measure entered mercury volume(Ziarani & Aguilera, 2012). The measurements were carried out at a temperature of 16°C, a humidity of 50%.…”

mentioning

confidence: 99%

Characteristics of dual media in tight‐sand gas reservoirs and its impact on reservoir quality: A case study of the Jurassic reservoir from the Kuqa Depression, Tarim Basin, Northwest China

et al. 2017

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The recent gas exploration in West China demonstrated that formation conditions of tight‐sandstone gas are distinct from typical ones in North America. One remarkable difference is that complicated tectonic conditions in the foreland basin of West China, especially the Himalayan tectonic movement, resulted in widely developed fractures in tight‐sand reservoirs. Thus, this work employed dual media to characterize tight‐sand reservoir system and explain the impact of dual media on tight‐sand gas reservoir by: (a) describing the feature of fractures and properties of Yinan 2 tight‐sand reservoir; (b) characterizing dual media with mercury intrusion porosimetry, full diameter and conventional core analysis; (c) discussing gas charging and accumulating in dual media based on the difference between dual media and tight‐sand rocks. Observation from cores, FMI images and thin sections suggested that macro‐ and micro‐fractures are widely distributed in Lower Jurassic Ahe Formation (J1a) tight sandstones, with dip angle of 70° to 80°. These fractures are strongly scale‐dependent with length of several centimetres to a few tens of centimetres and apertures of several hundreds to several thousands of microns. J1a tight‐sand reservoir is characterized by poor porosity, with an average value of 7.7%, whereas measured permeability varies from 0.01–100 mD. Intrusion and extrusion curves of dual media and tight‐sand rocks are significantly different from each other, while displacement pressure and medium saturation pressure of dual media are lower than tight‐sand rocks. Importantly, maximum pore throats of dual media are 1.75–32.22 times larger than juxtaposed tight‐sand rocks. The ratio of permeability between dual media and tight sandstone is up to 1,000, whereas the ratio of porosities only ranges from 1 to 1.5. Thus, dual media in tight‐sand reservoir represents high permeability system and matrix pores are primarily storage system. The impact of dual media on tight‐sand gas reservoir involves its position, temporal coupling of gas charging and growth. In terms of fracture growth prior to gas charge, multi‐force can work together as a driving force, and fractures as a flow system and matrix pores as a storage system linked by fractures; buoyancy is the primary driving force in fractures. In terms of gas charge prior to fracture growth, dual media can also exert a positive impact on gas charging when occurring in the inner part of tight‐sand reservoir defined by the critical throat threshold. However, dual media can also destroy the “inverted gas–water” and shrink tight‐sand gas reservoir when occurring at the original critical throat threshold.

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“…Percolation porosity is estimated to typically be 1-3% [52], which is insufficient to explain increases in injectivity: a percolation porosity of 3% would lead to maximum permeability increases of 0.45%, 0.50%, and 1.87% for the three reservoirs. However, tortuosity has been reported to vary widely at fixed porosity for similar rock or other porous medium samples [53]. A large decrease in tortuosity would cause a very substantial difference in permeability (e.g., a halving of tortuosity would increase permeability by a factor of four).…”

Section: Influence Of Porosity and Permeability Changes On Comentioning

confidence: 99%

Numerical Investigation into the Impact of CO₂-Water-Rock Interactions on CO₂ Injectivity at the Shenhua CCS Demonstration Project, China

Yang¹,

Li²,

Atrens³

et al. 2017

Geofluids

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A 100,000 t/year demonstration project for carbon dioxide (CO 2 ) capture and storage in the deep saline formations of the Ordos Basin, China, has been successfully completed. Field observations suggested that the injectivity increased nearly tenfold after CO 2 injection commenced without substantial pressure build-up. In order to evaluate whether this unique phenomenon could be attributed to geochemical changes, reactive transport modeling was conducted to investigate CO 2 -water-rock interactions and changes in porosity and permeability induced by CO 2 injection. The results indicated that using porosity-permeability relationships that include tortuosity, grain size, and percolation porosity, other than typical Kozeny-Carman porosity-permeability relationship, it is possible to explain the considerable injectivity increase as a consequence of mineral dissolution. These models might be justified in terms of selective dissolution along flow paths and by dissolution or migration of plugging fines. In terms of geochemical changes, dolomite dissolution is the largest source of porosity increase. Formation physical properties such as temperature, pressure, and brine salinity were found to have modest effects on mineral dissolution and precipitation. Results from this study could have practical implications for a successful CO 2 injection and enhanced oil/gas/geothermal production in low-permeability formations, potentially providing a new basis for screening of storage sites and reservoirs.

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Pore-throat radius and tortuosity estimation from formation resistivity data for tight-gas sandstone reservoirs

Cited by 77 publications

References 20 publications

Quantitative determination of pore and throat parameters in tight oil reservoir using constant rate mercury intrusion technique

Quantitative determination of pore and throat parameters in tight oil reservoir using constant rate mercury intrusion technique

Characteristics of dual media in tight‐sand gas reservoirs and its impact on reservoir quality: A case study of the Jurassic reservoir from the Kuqa Depression, Tarim Basin, Northwest China

Numerical Investigation into the Impact of CO₂-Water-Rock Interactions on CO₂ Injectivity at the Shenhua CCS Demonstration Project, China

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Pore-throat radius and tortuosity estimation from formation resistivity data for tight-gas sandstone reservoirs

Cited by 77 publications

References 20 publications

Quantitative determination of pore and throat parameters in tight oil reservoir using constant rate mercury intrusion technique

Quantitative determination of pore and throat parameters in tight oil reservoir using constant rate mercury intrusion technique

Characteristics of dual media in tight‐sand gas reservoirs and its impact on reservoir quality: A case study of the Jurassic reservoir from the Kuqa Depression, Tarim Basin, Northwest China

Numerical Investigation into the Impact of CO2-Water-Rock Interactions on CO2 Injectivity at the Shenhua CCS Demonstration Project, China

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Numerical Investigation into the Impact of CO₂-Water-Rock Interactions on CO₂ Injectivity at the Shenhua CCS Demonstration Project, China