Measurements of threshold capillary pressure with extreme low permeability rock

Oil–water relative permeability curve is an important parameter for analyzing the characters of oil and water seepages in low-permeability reservoirs. The fluid flow in low-permeability reservoirs exhibits distinct nonlinear seepage characteristics with starting pressure gradient. However, the existing theoretical model of oil–water relative permeability only considered few nonlinear seepage characteristics such as capillary pressure and fluid properties. Studying the influences of reservoir pore structures, capillary pressure, driving pressure and boundary layer effect on the morphology of relative permeability curves is of great significance for understanding the seepage properties of low-permeability reservoirs. Based on the fractal theory for porous media, an analytically comprehensive model for the relative permeabilities of oil and water in a low-permeability reservoir is established in this work. The analytical model for oil–water relative permeabilities obtained in this paper is found to be a function of water saturation, fractal dimension for pores, fractal dimension for tortuosity of capillaries, driving pressure gradient and capillary pressure between oil and water phases as well as boundary layer thickness. The present results show that the relative permeabilities of oil and water decrease with the increase of the fractal dimension for tortuosity, whereas the relative permeabilities of oil and water increase with the increase of pore fractal dimension. The nonlinear properties of low-permeability reservoirs have the prominent significances on the relative permeability of the oil phase. With the increase of the seepage resistance coefficient, the relative permeability of oil phase decreases. The proposed theoretical model has been verified by experimental data on oil–water relative permeability and compared with other conventional oil–water relative permeability models. The present results verify the reliability of the oil–water relative permeability model established in this paper.

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Formation Damage Issues Impacting the Productivity of Low Permeability, Low Initial Water Saturation Gas Producing Formations

Journal of Energy Resources Technology ◽

10.1115/1.1937420 ◽

2005 ◽

Vol 127 (3) ◽

pp. 240-247 ◽

Cited By ~ 65

Author(s):

D. Brant Bennion ◽

F. Brent Thomas

Keyword(s):

Capillary Pressure ◽

Water Saturation ◽

The United States ◽

Gas Production ◽

Pressure Effects ◽

Formation Damage ◽

Low Permeability ◽

Gas Reservoirs ◽

Initial Water ◽

The Impact

Very low in situ permeability gas reservoirs (Kgas<0.1mD) are very common and represent a major portion of the current exploitation market for unconventional gas production. Many of these reservoirs exist regionally in Canada and the United States and also on a worldwide basis. A considerable fraction of these formations appear to exist in a state of noncapillary equilibrium (abnormally low initial water saturation given the pore geometry and capillary pressure characteristics of the rock). These reservoirs have many unique challenges associated with the drilling and completion practices required in order to obtain economic production rates. Formation damage mechanisms affecting these very low permeability gas reservoirs, with a particular emphasis on relative permeability and capillary pressure effects (phase trapping) will be discussed in this article. Examples of reservoirs prone to these types of problems will be reviewed, and techniques which can be used to minimize the impact of formation damage on the productivity of tight gas reservoirs of this type will be presented.

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A New Unsteady-State Model for Calculating Oil-Water Relative Permeability of Low-Permeability/Ultra-Low Permeability Reservoirs

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.616-618.964 ◽

2012 ◽

Vol 616-618 ◽

pp. 964-969 ◽

Cited By ~ 1

Author(s):

Yue Yang ◽

Xiang Fang Li ◽

Ke Liu Wu ◽

Meng Lu Lin ◽

Jun Tai Shi

Keyword(s):

Porous Media ◽

Pressure Gradient ◽

Capillary Pressure ◽

Relative Permeability ◽

Oil Reservoirs ◽

Flow In Porous Media ◽

Low Permeability ◽

Threshold Pressure ◽

Flow Process ◽

Threshold Pressure Gradient

Oil and water relative permeabilities are main coefficients in describing the fluid flow in porous media; however, oil and water relative permeability for low - ultra low perm oil reservoir can not be obtained from present correlations. Based on the characteristics of oil and water flow in porous media, the model for calculating the oil and water relative permeability of low and ultra-low perm oil reservoirs, which considering effects of threshold pressure gradient and capillary pressure, has been established. Through conducting the non-steady oil and water relative permeability experiments, oil and water relative permeability curves influenced by different factors have been calculated. Results show that: the threshold pressure gradient more prominently affects the oil and water relative permeability; capillary pressure cannot influence the water relative permeability but only the oil relative permeability. Considering effects of threshold pressure gradient and capillary pressure yields the best development result, and more accordant with the flow process of oil and water in low – ultra low perm oil reservoirs.

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Computation of Productivity Index with Capillary Pressure Included and Its Application in Interpreting Production Data from Low-permeability Oil Reservoirs

10.2118/146648-ms ◽

2011 ◽

Cited By ~ 2

Author(s):

Kewen Li ◽

Zengwei Chen

Keyword(s):

Capillary Pressure ◽

Oil Reservoirs ◽

Productivity Index ◽

Production Data ◽

Low Permeability

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Mechanism of Overpressure Formation in Deeply Burial Sandstone

Applied Mechanics and Materials ◽

10.4028/www.scientific.net/amm.295-298.2736 ◽

2013 ◽

Vol 295-298 ◽

pp. 2736-2739

Author(s):

Hai Yan Hu

Keyword(s):

Hydrostatic Pressure ◽

Capillary Pressure ◽

Driving Force ◽

Low Permeability ◽

Gas Generation ◽

Tight Sandstone ◽

Gas Accumulation ◽

Fine Grained ◽

Sandstone Reservoirs ◽

Induced Fractures

Overpressure is often encountered in the Jurassic tight and the overpressure is closely associated with gas generation. The pressure transfer from the over-pressurized mudstones to adjacent tight sandstones might occur through overpressure induced-fractures. The fine-grained coal containing Jurassic sandstone is sensitive to compaction, and the porosity decreases dramatically with the increase of overlying load. As gas migrates into the tight sandstones, it must overcome the capillary pressure which is greater than the hydrostatic pressure. The gas charging pressure in the tight sandstone must be higher than the capillary pressure, resulting in an overpressure buildup within the tight sandstones. Gas shows, low permeability and strong diagenesis in the overpressure of the tight sandstone system have been observed. Additionally, capillary seals are identified as playing an important role in the mechanism of the overpressure formation in tight sandstone reservoirs. Overpressure might be a driving force to create induced fractures in the interval, which has applications for crossing-formation migration and gas accumulation.

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Measurement of threshold capillary pressure for seal rocks using the step-by-step approach and the residual pressure approach

Energy Procedia ◽

10.1016/j.egypro.2011.02.499 ◽

2011 ◽

Vol 4 ◽

pp. 5211-5218 ◽

Cited By ~ 16

Author(s):

Daisuke Ito ◽

Kohei Akaku ◽

Takashi Okabe ◽

Takashi Takahashi ◽

Takashi Tsuji

Keyword(s):

Capillary Pressure ◽

Residual Pressure ◽

Threshold Capillary Pressure

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The dynamic effect in capillary pressure during the displacement process in ultra-low permeability sandstone reservoirs

Capillarity ◽

10.26804/capi.2018.02.01 ◽

2018 ◽

Vol 1 (2) ◽

pp. 11-18 ◽

Cited By ~ 6

Author(s):

Ying Li ◽

Haitao Li ◽

Jianchao Cai ◽

Qirui Ma ◽

Jianfeng Zhang

Keyword(s):

Capillary Pressure ◽

Dynamic Effect ◽

Low Permeability ◽

Sandstone Reservoirs

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Fault seal modelling – the influence of fluid properties on fault sealing capacity in hydrocarbon and CO2 systems

Petroleum Geoscience ◽

10.1144/petgeo2019-126 ◽

2020 ◽

Vol 26 (3) ◽

pp. 481-497 ◽

Cited By ~ 4

Author(s):

Rūta Karolytė ◽

Gareth Johnson ◽

Graham Yielding ◽

Stuart M.V. Gilfillan

Keyword(s):

Contact Angle ◽

Capillary Pressure ◽

Petroleum Industry ◽

Interfacial Tensions ◽

Link Type ◽

Sealing Capacity ◽

Fluid Properties ◽

Supplementary Material ◽

Modelling Methods ◽

Threshold Capillary Pressure

Fault seal analysis is a key part of understanding the hydrocarbon trapping mechanisms in the petroleum industry. Fault seal research has also been expanded to CO2–brine systems for the application to carbon capture and storage (CCS). The wetting properties of rock-forming minerals in the presence of hydrocarbons or CO2 are a source of uncertainty in the calculations of capillary threshold pressure, which defines the fault sealing capacity. Here, we explore this uncertainty in a comparison study between two fault-sealed fields located in the Otway Basin, SE Australia. The Katnook Field in the Penola Trough is a methane field, while Boggy Creek in Port Campbell contains a high-CO2–methane mixture. Two industry standard fault seal modelling methods, one based on laboratory measurements of fault samples and the other based on a calibration of a global dataset of known sealing faults, are used to discuss their relative strengths and applicability to the CO2 storage context. We identify a range of interfacial tensions and contact angle values in the hydrocarbon–water system under the conditions assumed by the second method. Based on this, the uncertainty related to the spread in fluid properties was determined to be 24% of the calculated threshold capillary pressure value. We propose a methodology of threshold capillary pressure conversion from hydrocarbons–brine to the CO2–brine system, using an input of appropriate interfacial tension and contact angle under reservoir conditions. The method can be used for any fluid system where fluid properties are defined by these two parameters.Supplementary material: (1) Fault seal modelling methods and calculations, and (2) hydrocarbon and CO2 interfacial tensions and contact angle values collected in the literature are available at https://doi.org/10.6084/m9.figshare.c.4877049This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series

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