Gas-Water Capillary Pressure in Coal at Various Overburden Pressures

1976 ◽  
Vol 16 (05) ◽  
pp. 261-268 ◽  
Author(s):  
M.K. Dabbous ◽  
A.A. Reznik ◽  
B.G. Mody ◽  
P.F. Fulton ◽  
J.J. Taber
Keyword(s):  
Pore Structure ◽  
Pore Size ◽  
Capillary Pressure ◽  
Water Saturation ◽  
Petroleum Reservoir ◽  
Pressure Data ◽  
Overburden Pressure ◽  
Reservoir Rocks ◽  
Pore Compressibility ◽  
Different Types

Abstract Drainage air-water capillary-pressure curves were obtained for Pittsburgh and Pocahontas coals at various overburden pressures. Capillary-pressure data were used to investigate pore-size characteristics. Results were indicative of the complex pore structure of coal, consisting primarily of a network of macro- and microfractures. In most cases, however, displacement pressure and residual water saturation increased at higher overburden pressure. Reasonable agreement between measured relative permeabilities and those calculated from capillary-pressure data with Purcell's model was obtained for only a few samples. Fracture permeabilities computed from pore-size distribution were lower than permeabilities pore-size distribution were lower than permeabilities actually measured at the same overburden pressure. Helium porosity was considerably higher than porosity determined by water saturation, indicating porosity determined by water saturation, indicating inaccessible pore volume to water. Pore compressibility was determined under triaxial stress-loading conditions. Changes in porosity with overburden pressure were more significant at pressures below 1,500 psig. Above this pressure, pore compressibility appeared to approach a pressure, pore compressibility appeared to approach a constant value averaging about 0.5 × 10(−4) psi(−1) for the coal samples studied. Introduction Increased interest in underground coal gasification and coal-seam degasification for the purpose of producing clean energy stimulated fundamental producing clean energy stimulated fundamental research into the phenomena of multiphase fluid flow through coal. Two previous papers presented results of investigation of the air- and water-permeability and relative-permeability characteristics at various overburden pressures for two different types of coal. However, to understand the mechanisms of two-phase flow (usually gas and water) through a complex porous system such as coal, one needs a clear insight into the internal pore structure of coal and the interaction between pore structure of coal and the interaction between this structure and the associated fluids. Such knowledge of the make-up of the pore structure helps in modeling fluid flow through the system and in interpreting permeability and relative-permeability data. Interaction between the pore structure and fluids results in the capillary-pressure phenomena. Capillary-pressure data have been used extensively to determine the pore characteristics of many petroleum reservoir rocks and to relate these petroleum reservoir rocks and to relate these characteristics to the single- and two-phase flow behavior in the rock. It is also known that natural fracture systems are the principal source of flow capacity of many petroleum reservoir rocks and contribute materially petroleum reservoir rocks and contribute materially to the storage capacity of some. Changes in fracture capacity resulting from changes in net overburden pressure have an important influence on the flow pressure have an important influence on the flow properties of the rock, as reported by Jones. In our properties of the rock, as reported by Jones. In our previous work with coal, which is a naturally previous work with coal, which is a naturally fractured system, absolute and effective permeabilities were found to be highly sensitive to overburden pressure (pov). Thus, it would be expected that the pressure (pov). Thus, it would be expected that the effect of Pov on the fracture flow capacity, capillary pressure, and pore compressibility is more dramatic pressure, and pore compressibility is more dramatic for coal. The internal structure of coal has been studied by microscopic methods, gas sorption measurements, and by mercury porosimetry. Data on helium porosity of different types of coal also can be porosity of different types of coal also can be found in Ref. 5. However, we are not aware of any determinations of capillary pressure in coal at different overburden pressures. In this paper gas-liquid capillary-pressure relationships for coal at different overburden pressures are presented. pressures are presented. SPEJ P. 261

EXPERIENCE WITH DETERMINATION OF WATER SATURATION FROM CORE IN THE COSSACK FIELD

1993 ◽  
Vol 33 (1) ◽  
pp. 39
Author(s):  
D. Lasserre & C.F. Choo
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
Pressure Data ◽  
Reservoir Rocks ◽  
Saturation Parameter ◽  
The Core ◽  
Sandstone Reservoir

Water saturation measurements were made on core in two Cossack field appraisal wells to investigate the discrepancy between the water saturation calculated from logs and that observed from the capillary pressure data in the Cossack-1 discovery well. The core measurements resulted in a more accurate water saturation parameter which was then used to estimate the volume of hydrocarbons in place. The core measurements also provided valuable information about the wettability of the reservoir rocks. The results of this exercise also highlighted the uncertainty attached to the water saturation determination from logs in what was an apparently simple case of a thick, clean sandstone reservoir.

scholarly journals Experimental investigation of the effects of different types of fracturing fluids on the pore structure characteristics of Shale Reservoir Rocks

2019 ◽  
Vol 38 (3) ◽  
pp. 682-702 ◽  
Author(s):  
Zepeng Sun ◽  
Yue Ni ◽  
Yongli Wang ◽  
Zhifu Wei ◽  
Baoxiang Wu ◽  
...  
Keyword(s):  
Electron Microscopy ◽  
Scanning Electron Microscopy ◽  
Pore Structure ◽  
Reservoir Rocks ◽  
Fracturing Fluids ◽  
Different Types ◽  
Shale Reservoir ◽  
Mineral Compositions ◽  
Over Time ◽  
Scanning Electron

The chemical and physical capabilities of shale can be altered by the interactions between fracturing fluid and shale formation, affecting the long-term reservoir productivity. To obtain information regarding how fracturing fluids with different components impact the pore structure, porosity and mineral compositions of shale reservoir rocks over time, two different types of commercial fracturing fluids (slick water and crosslinked gel) were used to react with the shales from Longmaxi Formation of Lower Silurian in the Sichuan Basin of South China. Experiments were conducted with various time intervals (1, 4 and 10 days) in a reactor at 50 MPa and 100°C, and then analytical methods including X-ray diffraction, low pressure nitrogen adsorption, field emission scanning electron microscopy and porosity measurement were used to examine the changes of mineralogical compositions, pore structure and porosity. The results demonstrated that the mineral compositions of shale samples were significantly changed after treatment with two different fracturing fluids for 4 days. The analysis of field emission scanning electron microscopy revealed that the carbonate minerals were dissolved and developed many dissolution pores after slick water treatment, while the crosslinked gel mainly caused the precipitation of carbonate minerals. After exposure to different fracturing fluids, the total pore volume and specific surface area decreased over time. Moreover, the fractal dimensions (D1 and D2) of shale showed an apparent decrease trend after treatment with two different fracturing fluids, indicating that the pore surface and structure become smooth and regular. The porosity of shale significantly decreased by 15.9% and 17.8%, respectively, after 10 days of slick water and crosslinked gel treatment. These results indicated that the injection of the two different types of fracturing fluids may negatively impact the shale gas production through reducing the nanopore structure and porosity of shale reservoir rocks.

Application of Air-Mercury and Oil-Air Capillary Pressure Data In the Study of Pore Structure and Fluid Distribution

1966 ◽  
Vol 6 (01) ◽  
pp. 55-61 ◽  
Author(s):  
J.J. Pickell ◽  
B.F. Swanson ◽  
W.B. Hickman
Keyword(s):  
Interfacial Tension ◽  
Pore Structure ◽  
Capillary Pressure ◽  
Fluid Distribution ◽  
Pore Geometry ◽  
Residual Oil ◽  
Pressure Data ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Phase Saturation

Abstract Many physical properties of the porous media-immiscible liquid system are dependent upon the distribution of fluids within the pores; this in turn, is primarily a function of pore structure, liquid-liquid interfacial tension and liquid-solid wetting conditions. The capillary pressure hysteresis process provides a means of investigating the influence of pore structure upon fluid distribution for consistent surface conditions. Investigations indicate that residual non-wetting-phase saturations following the imbibition process (i.e., wetting phase displacing non-wetting phase) are dependent upon both pore structure and initial non-wetting phase saturation and suggest that residual fluid is distributed to discontinuous globules, one to a few pore sizes in dimension, through the entire range of pore sizes originally occupied. It appears that air-mercury capillary pressure data adequately reflect the distribution of fluids in a water-oil system when strong wetting conditions prevail. An oil-air counter-current imbibition technique has also been found to provide a rapid means of obtaining residual-initial saturation data. In a majority of cases, residual saturations determined from the oil-air or air-mercury process reasonably approximate residual oil and saturation following water drive of a strongly water-wet medium. Introduction A reliable estimate of recoverable reserves depends not only on the amount of original oil-in-place but also on pore geometry and distribution of fluids within the pores. A critical parameter determining the recovery from a reservoir under waterflood, for example, is the amount and distribution of residual oil within the various rock types present. The purpose of this paper is to investigate the mechanism of capillary trapping and assess its importance in laboratory measurements of residual oil saturation. The degree of wettability of a reservoir rock is recognized as an important factor in waterflood or imbibition experiments. In this paper, however, only the water-wet case has been considered. Considerable experimental evidence1 suggests that for water-wet rocks, capillary forces predominate in the distribution of fluids and that viscous forces in the range normally of interest in the reservoir have a minimum influence on residual oil saturation. It follows that if the ultimate recovery is controlled by pore geometry, a unique residual non-wetting phase saturation should exist for a given set of initial conditions. Two laboratory procedures found to be extremely useful in the study of pore structure and degree of fluid interconnection at various saturations are described. Although air-mercury capillary injection curves have been used2 previously to characterize the drainage case, the withdrawal or imbibition case can provide valuable supplementary data. The air-mercury process, however, has several disadvantages; it is difficult to run in a sufficiently accurate manner, mercury does not always act as a strongly non-wetting liquid and in the air-mercury process the sample is rendered unsuitable for future analyses. An alternative process is described in which air is the non-wetting phase and naptha, heptane, octane or toluene is the wetting phase. Interfacial Tension and Capillary Pressure Interfacial tension between immiscible fluids is due to the difference in attraction of like molecules as compared with their attraction to molecules of the neighboring fluid. This net attraction results in a tension at the interface. To extend the interface; thus, interfacial tension s can also be thought of as free surface energy. Interfacial tension is normally expressed as dynes/cm, and interfacial energy is measured in ergs/cm2 hence, both have dimensions mLt-2 and are numerically equal.

Investigation of Pore Structure for Manufactured Sand Mortar

2014 ◽  
Vol 534 ◽  
pp. 39-51
Author(s):  
Zheng Hong Tian ◽  
Jing Wu Bu
Keyword(s):  
Pore Structure ◽  
Pore Size ◽  
Water Saturation ◽  
Total Porosity ◽  
Threshold Region ◽  
Fine Aggregate ◽  
Test Results ◽  
Natural Sand ◽  
Manufactured Sand ◽  
Threshold Radius

This paper focuses on the pore structure parameters of mortars produced with manufactured sand and natural sand via water saturation and MIP methods. Test results show that, total porosity, as well as compressive strength, of manufactured sand mortar, is higher than that of natural sand mortar at fixed w/c and s/c ratio. Furthermore, considerable volume of large pores present in specimens of manufactured sand at higher w/c ratio rather not at the lower w/c ratio, which caused by the larger binder-aggregate interface. Manufactured fine aggregate in mortar probably accelerate hydrated reaction of cement, which result in the most probable pore size is finer than that of natural sand mortar. It can be concluded that the threshold region becomes flatten and threshold radius increases due to the aggregate volume concentration rises. Finally, a new theoretical model with a double-lognormal distribution function is demonstrated to be reasonable to fit pore size distribution in mortars.

scholarly journals Evaluation of calculated connate water saturation values in case of unconventional rock samples

2021 ◽  
Vol 11 (1) ◽  
pp. 58-68
Author(s):  
Ferenc Remeczki
Keyword(s):  
Pore Size Distribution ◽  
Pore Size ◽  
Size Distribution ◽  
Production Technology ◽  
Pore Radius ◽  
Water Saturation ◽  
Unconventional Reservoirs ◽  
Reservoir Rocks ◽  
Connate Water ◽  
Rock Samples

The present study represents possibilities of calculating the connate water saturation - CWS - values of samples from unconventional reservoirs and how to evaluate the obtained result. CWS is an extremely important property of the reservoir rocks. It basically determines the value of the resource and can also predict production technology difficulties. For the samples included in the measurement program, significant or extremely high CWS values were determined. Analysis of the corrected pore size distribution proved to be the most appropriate method for interpreting CWS values, although, it also shows some correlation with the most frequent pore radius - MFPR - and porosity.

scholarly journals Predicting the Relative Permeability of Water Phase Based on Theory of Coupled Electricity-Seepage and Capillary Bundle Model

2015 ◽  
Vol 8 (1) ◽  
pp. 344-349 ◽  
Author(s):  
Xinmin Ge ◽  
Yiren Fan ◽  
Donghui Xing ◽  
Jingying Chen ◽  
Yunhai Cong ◽  
...  
Keyword(s):  
Fractal Dimension ◽  
Pore Structure ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Water Saturation ◽  
Saturation Index ◽  
Dynamic Parameters ◽  
Empirical Formulas ◽  
Capillary Bundle ◽  
Capillary Walls

An analytical water relative model based on the theory of coupled electricity-seepage and capillary bundle pore structure is described. The model shows that the relative permeability of water is affected by two kinds of parameters, which are depicted as static parameters and dynamic parameters. Revised Kozeny-Carman equation and Archie formulas are introduced to deduce the model, which enhance the characterization ability of pore structure. Two displacing states, where we summarized that oil coats capillary walls and oil occupies capillary centers are also discussed for optimization of the model. In contrast to existing empirical formulas where relative permeability is strongly related to capillary pressure and fractal dimension, we introduce only water saturation and saturation index as input parameters, which make the model simpler to use. Petrophysics and unsteady relative permeability experiments (oil displacing water) are carried out to testify the two models. The fitting results show that for oil displacing experiments presented in this paper, the displacing state where oil coats capillary walls is suitable to predict the relative permeability of water.

A New Multiphysics Method for Simultaneous Assessment of Permeability and Saturation-Dependent Capillary Pressure in Hydrocarbon-Bearing Rocks

SPE Journal ◽  
2020 ◽  
pp. 1-17
Author(s):  
Artur Posenato Garcia ◽  
Zoya Heidari
Keyword(s):  
Pore Structure ◽  
Capillary Pressure ◽  
Size Distribution ◽  
Water Saturation ◽  
Rock Physics ◽  
Rock Fabric ◽  
The Core ◽  
Directional Permeability ◽  
Water Saturated ◽  
Pore Body

Summary Cost-effective exploitation of heterogeneous/anisotropic reservoirs (e.g., carbonate formations) relies on accurate description of pore structure, dynamic petrophysical properties (e.g., directional permeability, saturation-dependent capillary pressure), and fluid distribution. However, techniques for reliable quantification of permeability still rely on model calibration using core measurements. Furthermore, the assessment of saturation-dependent capillary pressure has been limited to experimental measurements, such as mercury injection capillary pressure (MICP). The objectives of this paper include developing a new multiphysics workflow to quantify rock-fabric features (e.g., porosity, tortuosity, and effective throat size) from integrated interpretation of nuclear magnetic resonance (NMR) and electric measurements; introducing rock-physics models that incorporate the quantified rock fabric and partial water/hydrocarbon saturation for assessment of directional permeability and saturation-dependent capillary pressure; and validating the reliability of the new workflow in the core-scale domain. To achieve these objectives, we introduce a new multiphysics workflow integrating NMR and electric measurements, honoring rock fabric, and minimizing calibration efforts. We estimate water saturation from the interpretation of dielectric measurements. Next, we develop a fluid-substitution algorithm to estimate the T2 distribution corresponding to fully water-saturated rocks from the interpretation of NMR measurements. We use the estimated T2 distribution for assessment of porosity, pore-body-size distribution, and effective pore-body size. Then, we develop a new physically meaningful resistivity model and apply it to obtain the constriction factor and, consequently, throat-size distribution from the interpretation of resistivity measurements. We estimate tortuosity from the interpretation of dielectric-permittivity measurements at 960 MHz by applying the concept of capacitive formation factor. Finally, throat-size distribution, porosity, and tortuosity are used to calculate directional permeability and saturation-dependent capillary pressure. We test the reliability of the new multiphysics workflow in the core-scale domain on rock samples at different water-saturation levels. The introduced multiphysics workflow provides accurate description of the pore structure in partially water-saturated formations with complex pore structure. Moreover, this new method enables real-time well-log-based assessment of saturation-dependent capillary pressure and directional permeability (in presence of directional electrical measurements) in reservoir conditions, which was not possible before. Quantification of capillary pressure has been limited to measurements in laboratory conditions, where the differences in stress field reduce the accuracy of the estimates. We verified that the estimates of permeability, saturation-dependent capillary pressure, and throat-size distribution obtained from the application of the new workflow agreed with those experimentally determined from core samples. We selected core samples from four different rock types, namely Edwards Yellow Limestone, Lueders Limestone, Berea Sandstone, and Texas Cream Limestone. Finally, because the new workflow relies on fundamental rock-physics principles, permeability and saturation-dependent capillary pressure can be estimated from well logs with minimum calibration efforts, which is another unique contribution of this work.

Effects of pore structure and wettability on the electrical resistivity of partially saturated rocks—A network study

Geophysics ◽  
1997 ◽  
Vol 62 (4) ◽  
pp. 1151-1162 ◽  
Author(s):  
Ravi J. Suman ◽  
Rosemary J. Knight
Keyword(s):  
Pore Structure ◽  
Pore Size Distribution ◽  
Pore Size ◽  
Size Distribution ◽  
Network Model ◽  
Water Saturation ◽  
Archie’S Law ◽  
Partially Saturated ◽  
Saturation Exponent ◽  
Wetting Film

A network model of porous media is used to assess the effects of pore structure and matrix wettability on the resistivity of partially saturated rocks. Our focus is the magnitude of the saturation exponent n from Archie's law and the hysteresis in resistivity between drainage and imbibition cycles. Wettability is found to have the dominant effect on resistivity. The network model is used to investigate the role of a wetting film in water‐wet systems, and the behavior of oil‐wet systems. In the presence of a thin wetting film in water‐wet systems, the observed variation in n with saturation is reduced significantly resulting in lower n values and reduced hysteresis. This is attributed to the electrical continuity provided by the film at low‐water saturation between otherwise physically isolated portions of water. Oil‐wet systems, when compared with the water‐wet systems, are found to have higher n values. In addition, the oil‐wet systems exhibit a different form of hysteresis and more pronounced hysteresis. These differences in the resistivity response are attributed to differences in the pore scale distribution of water. The effects of pore structure are assessed by varying pore size distribution and standard deviation of the pore size distribution and considering networks with pore size correlation. The most significant parameter is found to be the pore size correlation. When the sizes of the neighboring pores of the network are correlated positively, the magnitude of n and hysteresis are reduced substantially in both the water‐wet and oil‐wet systems. This is attributed to higher pore accessibility in the correlated networks. The results of the present study emphasize the importance of conducting laboratory measurements on core samples with reservoir fluids and wettability that is representative of the reservoir. Hysteresis in resistivity can be present, particularly in oil‐wet systems, and should be considered in the interpretation of resistivity data.

Effect of Overburden Pressure on Some Properties Of Sandstones

1962 ◽  
Vol 2 (04) ◽  
pp. 360-366 ◽  
Author(s):  
Valery M. Dobrynin
Keyword(s):  
Experimental Data ◽  
Physical Properties ◽  
Pore Pressure ◽  
Clay Minerals ◽  
Elastic Waves ◽  
Water Saturation ◽  
Porous Rocks ◽  
Overburden Pressure ◽  
Pore Compressibility ◽  
Internal Pore

Abstract Experimental data demonstrate that physical properties of porous rocks change under pressure. In this paper an assumption is made and proved that under pressure the changes of physical properties such as porosity, density, permeability, resistivity and velocity of elastic waves are controlled to a large extent by the pore compressibility of rocks. It is also shown that the pore compressibility of rocks can be determined, within the range of pressures from 0 to 20,000 psi, by knowing the maximum pore compressibility and the magnitude of the pressure. Mathematical equations were developed which permit one to define changes in physical properties of porous rocks under pressure. These equations were verified by experimental data obtained from the study of sandstones. Introduction In studying the behavior of porous rocks under pressure in the field of petroleum technology, the most interesting aspect is the observation of those properties which characterize the rocks as possible reservoirs for example, porosity, permeability, resistivity, density and be velocity of elastic waves. The literature dealing with this problem mainly contains data concerning the study of only one or at most two of these parameters, but not of the group as a whole. An attempt is made in this paper to find general equations involving each of these parameters, which will permit the study of the behavior of rocks under pressure. All experimental data used here were obtained from the investigation of consolidated sandstones. EXPERIMENTAL In addition to the use of published experimental data, an experiment was carried out which studied the main physical properties of sandstones under pressure. Two homogeneous quartz sandstones were chosen for this purpose:the Torpedo sandstone bona Kansas, andthe Medina sandstone from Ohio. The porosity of the Torpedo sandstone was 20.2 per cent, and that of the Medina 8.7 per cent. Permeabilities were 45 md and less than 1 md, respectively. Each sandstone contained about 5 per cent clay minerals, consisting mostly of kaolinite and chlorite, which were distributed quite evenly throughout the samples. One cylindrical sample 2 in. in diameter and 5 in. in length was cut from each sandstone and then saturated in a vacuum with a 3N solution of NaCl. This high concentration was used in order to obtain true formation factors and to decrease the swelling of the clay minerals. The methods of mounting the samples and measuring the changes in porosity and resistivity were practically the same as those described by Fatt and Mann. Changes of resistivity under pressure were studied for sandstones with 100 per cent water saturation, and for sandstones with the irreducible water saturation. The irreducible saturation was obtained by enclosing the saturated rock samples in relatively fine silicate powder so as to remove the water by capillary action. This procedure is described by Orkin and Kuchinski. Changes of permeability with pressure were determined at room temperature using nitrogen as the flowing medium. In studying the effects of pressure, one series of measurements was made using an internal pore pressure Pi equal to the atmospheric pressure, while the overburden pressure P. ranged from 0 to 20,000 psi. A second series of measurements was used over the same range of overburden pressure, but with an internal pore pressure of 1,800 psi When the results were compared on the basis of net overburden pressure (P, - 0.85 Pi ), there was practically no difference for these two sandstones. The origin of the factor 0.85 in the expression for net overburden pressure is given by Brandt, Fatt and Geertsma. SPEJ P. 360^

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