Relative Permeability Characteristics Research Articles

Effect of Confining Pressure on CO2-Brine Relative Permeability Characteristics of Sandstone in Ordos Basin

CO2-brine relative permeability significantly impacts CO2 injection and is a key parameter for carbon dioxide storage simulation in saline aquifers. In the study of relative permeability, factors such as temperature, pressure, and reservoir rock physical properties play a crucial role. To better understand the impact of confining pressure on the CO2-brine relative permeability characteristics of sandstone in the Ordos Basin, five sets of CO2-brine relative permeability data were obtained through unsteady-state displacement tests conducted at various confining pressures ranging from 12 to 20 MPa. The research findings indicate that with an increase in confining pressure there is a slight decrease in irreducible brine saturation. Furthermore, the CO2 relative permeability in the irreducible brine state decreased by 57% as the pressure increased from 12 MPa to 20 MPa. The study demonstrates notable differences in the CO2-brine relative permeability curves under varying confining pressure conditions. As the confining pressure increases, the CO2 relative permeability curve decreases, while the brine relative permeability increases. The change in brine relative permeability is not as pronounced as that of CO2. These experimental results offer essential support for subsequent numerical calculations and practical applications in engineering. Experimental research holds significant importance in the assessment of storage potential and the prediction of the evolutionary patterns of CO2 migration.

The differences on gas–water relative permeability characteristics of low and high rank coal and its controlling factors

A comprehensive comparison was conducted in terms of the gas–water relative permeability characteristics of high rank coals from south Qinshui Basin and low rank coals from Erlian Basin, China. The results show that: High rank coal samples are featured with a larger percentage of micropores. Compared with high rank coal samples, low rank ones display a smaller irreducible water saturation (S wo) and higher methane (K rg) and water (K rw) permeability and wider spans of two-phase flow region. High rank coal samples with a large percent of micropores are featured with a larger S wo and a narrower two-phase flow span. Gas displacement pressure increases K rg, while decreases K rw and S wo, and the changing rule is more pronounced in low rank coal samples. The effective stress is inversely proportional to the K rg and the span of two-phase flow, whereas proportional to the K rw. Influenced by effective stress, the dynamic changes of the cross points are more obvious in the low rank coal samples, however that of two-phase flow spans and S wo are not so pronounced. The conclusion will be helpful for CBM exploration and development.

Simulation Study of sc-CO2 Based Silylation for Decreasing Severity of Water Blockage and Salt Precipitation during Geological CO2 Storage in Deep Saline Aquifers

Deep saline aquifers are often favorable for underground CO2 sequestration due to their large capacity and relatively low likelihood for resource conflicts. However, many possible issues can arise during CO2 injection. Often these aquifers have a significant salinity level (as these often present minimal resource conflict issues) and as such salt precipitation near the injection wellbore can be problematic. Furthermore, when water blockage occurs, salt precipitation can be exacerbated since large amounts of water remain near the wellbore. Altering the rock wettability towards less water-wet can alleviate water blockage and in turn reduce the likelihood or severity of salt precipitation. Previous lab experiments have shown that supercritical CO2 (sc-CO2)-based silylation can effectively functionalize rock surfaces with hydrophobic silanes. In this study, numerical models were constructed to evaluate the combined effects of multi-phase fluid flow, water evaporation and salt precipitation assuming a change in wettability (thus impacting the relative permeability characteristics of the reservoir) resulting from the silylation process. The aim of this study is to evaluate the efficacy of this chemical treatment to address near wellbore salt precipitation induced by CO2 injection. According to the simulation results, a decrease in injectivity due to salt precipitation is more significant when water blockage is also present. Injectivity is deteriorated prominently in high salinity reservoirs with water blockage since evaporation into the injected CO2 phase will cause significant salt precipitation. In a representative formation, the injectivity decline is worse (up to 68.6% relative injectivity change (RIC)) when both salt precipitation and water blockage are considered since the latter provides more trapped brine inducing more salt accumulation around the wellbore. With hydrophobic silylation, the combined effects of salt precipitation and water blockage on RIC are decreased on an absolute basis by up to 7%. Depending on techno-economic considerations, this method is encouraged to be implemented as early as possible during a CO2 injection program to minimize salt accumulation from the outset.

Experimental analysis of the pore structure, relative permeability, and water flooding characteristics of the Yan'an Formation sandstone, southwestern Ordos Basin

The oil and gas potential of the Yan'an Formation in the Ordos Basin has yet to be fully tapped. In this study, the pore structure, mobile fluid saturation, and water flooding micro-mechanism of the Yan'an Formation sandstone are systematically studied through the application of a series of rock physics and fluid experiments. The results show that there is a good positive correlation between porosity and permeability, and the reservoirs are divided into types Ⅰ, Ⅱ, and Ⅲ. Mercury injection tests show that the average pore throat radius of the oil-bearing reservoir ranges from 1 to 7 μm. The displacement pressure of the Yan'an Formation is also relatively low, and it decreases from 0.1 MPa to 0.01 MPa as the rock porosity increases from 11% to 18%. NMR tests show that small (diameter <0.5 μm) and medium pores (diameter ranging from 0.5 to 2.5 μm) are predominant in the reservoir. Different types of reservoirs have different characteristics of relative permeability curve. In addition, when the average oil recovery rate is less than 1 ml/min, the oil displacement efficiency increases faster. However, when the average oil recovery rate is between 1–3.5 ml/min, the oil displacement efficiency is maintained at around 27%–30%. Physical properties of the reservoir, pore-throat structure, experimental pressure difference, and pore volume injected — all have significant effects on oil displacement efficiency. For Type Ⅰ and Type Ⅱ reservoirs, the increase of the pore volume injected has a significant effect on oil displacement efficiency. However, for Type Ⅲ reservoirs, the change of pore volume injected has insignificant effect on oil displacement efficiency. This study provides a reference for the formulation of estimated ultimate recovery (EUR) measures for similar sandstone reservoirs.

Effect of H2S content on relative permeability and capillary pressure characteristics of acid gas/brine/rock systems: A review

Geological storage of acid gas has been identified as a promising approach to reduce atmospheric carbon dioxide (CO 2 ), hydrogen sulfide (H 2 S) and alleviate public concern resulting from the sour gas production. A good understanding of the relative permeability and capillary pressure characteristics is crucial to predict the process of acid gas injection and migration. The prediction of injection and redistribution of acid gas is important to determine storage capacity, formation pressure, plume extent, shape, and leakage potential. Herein, the existing experimental data and theoretical models were reviewed to gain a better understanding of the issue how the H 2 S content affects gas density, gas viscosity, interfacial tension, wettability, relative permeability and capillary pressure characteristics of acid gas/brine/rock systems. The densities and viscosities of the acid gas with different H 2 S mole fractions are both temperature- and pressure-dependent, which vary among the gas, liquid and supercritical phases. Water/acid gas interfacial tension decreases strongly with increasing H 2 S content. For mica and clean quartz, water contact angle increases with increasing H 2 S mole fraction. In particular, wettability reversal of mica to a H 2 S -wet behavior occurs in the presence of dense H 2 S. The capillary pressure increases with decreasing contact angle. At a given saturation, the relative permeability of a fluid is higher when the fluid is nonwetting. The capillary pressure decreases with decreasing interfacial tension at a given saturation. However, the existing datasets do not show a consistent link between capillary number and relative permeability. The capillary pressure decreases with increasing H 2 S mole fraction. However, there is no consensus on the effect of the H 2 S content on the relative permeability curves. This may be due to the limited availability of the relative permeability and capillary pressure data for acid gas/brine/rock systems; thus, more experimental measurements are required.

Impact of PAM-ZnO nanocomposite on oil recovery

A new nanocomposite (NC) comprising of ZnO nanoparticles and polyacrylamide (PAM) polymer hybrid agent is investigated for enhanced oil recovery in sandstone and carbonate rocks. A range of measurements are conducted to examine the behavior of NCs including NC synthesis and characterization, NC physical properties, stability analysis, IFT, and wettability as a function of NC concentration (from 100 to 1000 ppm). Furthermore, core flood tests are performed to evaluate oil recovery and relative permeability characteristics and a numerical model is established, and history matched.The zeta potential tests verified the stability of the set NC at 200 ppm concentration in water-based solutions, while a clear reduction in IFT from 29 mN/m to 5.5 mN/m was observed at the same NC concentration. A notable shift is observed in contact angle from 133° to 13° for the sandstone rock at a 1000 ppm NC concentration suggesting a significant shift in wettability from oil-wet to strongly water-wet after NC injection while the optimal contact angle for the sandstone occurred at NC concentration of 200 ppm. Furthermore, the flooding NCs resulted in a 16.05 % increase in oil recovery factor compared to seawater flood for sandstone while a 26 % increase was recorded for carbonate sample. Likewise, the mobility ratio after NC flooding compared to seawater flooding decreased from 8.56 to 1.46. We obtained a good history match of the water cut and oil recovery factor data by creating the core dimension model. In addition, according to the fluid distribution pattern (one of the simulator outputs), the fingering phenomenon was delayed after flooding the NC compared to seawater. This study provides new insights into the impact of nanocomposite on oil recovery enhancement in sandstone and carbonate formations.

Experimental Study on Gas–Water Relative Permeability Characteristics of Tight Sandstone Reservoir in Ordos Basin

Accurate measurement of relative permeability curve is the basis for evaluating gas reservoir performance. The unsteady-state method could bring significant measurement error for low-permeability cores. However, it is difficult to control the constant gas flow rate in the traditional steady-state method, which obstacles the experimental operation. In this study, an improved steady-state method was proposed. First, the pressure value obtained from the experiment, when the gas permeability no longer changed with the average pressure on the rock core, was set as the testing pressure. Then, the gas was injected under constant pressure, and the water was injected with a constant flow rate. Finally, the relative permeability values of gas and water phases were calculated based on Darcy’s law. Comparative analysis of the results of the relative permeability curves under formation pressure and pressure with negligible slip effect indicates that the relative permeability curves are the same in gas and water phases, proving the feasibility of the new method. Further, the results were compared with those of the test method at normal pressure, the water-phase relative permeability showed no significant change, the relative permeability of gas phase was larger, the two-phase flow area became wider, and the irreducible water saturation was lower than that at the normal pressure. This result reflects that pressure does not significantly affect the flow of wetting phase but tremendously influences the nonwetted phase under low pressure. The relationship between relative permeability and water saturation is linear in the semilogarithmic coordinate diagram and can be described by using the following relationship: ln k rg / k rw = a S w + ln b . With the decrease in the core permeability, relative permeability curve, and isotonic point moved to the right, irreducible water saturation gradually increased, and residual gas saturation decreased, indicating that the smaller permeability induced a lower gas-phase flow capacity.

Migration of carbon dioxide in sandstone under various pressure/temperature conditions: From experiment to simulation

AbstractThe pressure and temperature of a target CO2 storage reservoir can significantly affect the migration and relative permeability characteristics which can ultimately determine the carbon storage capacity and storage integrity of target formations. To understand these impacts, a CO2 core‐flooding experiment was conducted on a brine‐saturated sandstone containing a single clay interlayer perpendicular to the flow direction at a temperature of 313 K and a pressure of 8 MPa and the fluid distribution was monitored by a high‐resolution X‐ray computed tomography (X‐CT) scanner. Further, a one‐dimensional model was established to reproduce the CO2 flow behavior inside the sample under the same experimental condition and then the model was extended to different temperatures (313 and 350 K) and pressures (6, 8, 12, and 17.4 MPa). The experimental results show that the CO2 preferentially created high‐CO2‐saturation flow pathways which then expanded until they were large enough to transport the CO2 at the prescribed flow rate. The sub‐core scale heterogeneity also had significant effects on the CO2 migration, forming a barrier to downstream flow. The simulation results show that at a given temperature, the CO2 front migration velocity decreased with increasing reservoir pressure while the CO2 saturation along the pathways increased. Comparing simulations when the reservoir pressure was the same, the front‐migration velocity increased with increasing temperature, and the CO2 saturation along the pathways decreased. Meanwhile, the influence of temperature and pressure on CO2 saturation distribution was more evident in the parts of the core with high residual brine saturation. © 2022 Society of Chemical Industry and John Wiley &amp; Sons, Ltd.

Influence of long-term stored oil on wettability and its recovery in depleted petroleum reservoirs

Underground oil storage is a viable technique to increase energy security in the context of global concern for oil demand and supply. When the economic conditions permit, it makes sense to store oil in water-flooded, water-wet sandstone reservoirs that are geographically ubiquitous and abundant, structurally safe, and cost-effective for storing large amounts of crude oil safely. Due to long-term restoring oil contacting with the surface of rocks in such reservoirs, the property of the reservoir rocks may be changed, and the performance of oil reproduction may be different. These important factors are related to the change of wetting behavior of reservoirs, which directly affects the recovery rate of stored oil and the relative permeability characteristic of oil and water flow during the reproduction of stored crude oil in a water-wet depleted petroleum reservoir. Unfortunately, there is a lack of study on these research areas. This study investigates the change of wettability in such reservoirs and its influence on the production of stored oil by a second water flooding process. Several experimental techniques, including NMR and centrifuge measurements (USBM), and two-phase flow relative permeability measurement, are employed to investigate wetting behavior in crude oil/water/rock systems and two-phase flow characteristics when the crude oil is reinjected and stored oil is reproduced by water flooding in the present work.Based on the results of NMR and centrifuge experiments, the wettability of the core aged with crude oil was altered from strongly water-wet to weakly water-wet with an increase in aging time. NMR and USBM wettability indexes showed a good agreement suggesting a change into weakly water wetness. It is consistent with the change of relative permeability characteristics for first and second water flooding. We also reported that 77.5% of stored oil is recovered by second water flooding. Oil recovery factors and the characteristic parameters, Swi, Ko(Swi), Soi, Sor, Sw(max), and Kw(Sor) were experimentally determined for initial and second water flooding. Although not all of the stored crude oil has been recovered due to wettability change and oil film left the pore’s surface on the rock, the desired recovery factor has been achieved during the second water flooding.

Determination of gas-water seepage characteristics with consideration of dynamic pore-throat structure in a tight sandstone gas formation

In this paper, a pragmatic and integrated technique has been developed to experimentally determine the gas-water seepage characteristics with consideration of dynamic pore-throat structure in a tight sandstone gas formation due to a decrease in pore pressure. Conventional experiments were conducted to obtain porosity and permeability of core samples collected from a tight sandstone gas reservoir in the Ordos basin. Then, gas and water flow experiments integrated with the nuclear magnetic resonance (NMR) measurement were employed to obtain the dynamic characteristics of relative permeability curves due to changes in pore-throat structure, while gas permeabilities under different conditions are corrected with consideration of the slippage effect and dynamic pore-throat characteristics. Subsequently, irreducible water saturation and water blocking coefficient were obtained by combining the measured NMR T2 spectrum and gas-water volume, which were used to examine the effects of dynamic evolution of a pore-throat structure on the gas-water micro-distribution and percolation capacity. In the case that the decreased pore pressure inevitably leads to the contraction of pores and throats, although the absolute value of permeability decrease is larger for samples with higher permeability, the relative proportion of permeability decrease is larger for samples with lower permeability, indicating a stronger stress sensitivity. With such a decrease of pore pressure, gas and water relative permeability curves are shifted downwards to the right-hand side, during which the flowing ability of the gas-water system is weakened. The increase in irreducible water saturation is found to be greater in the larger throats, while the relative permeability characteristics and irreducible water saturation of a core sample with a higher permeability have larger changes due to the influence of the dynamic pore-throat structure under the same stress variation. The change in the pore-throat structure due to a decrease in pore pressure imposes the greatest impact on the seepage characteristics at the initial stage.

Experimental Study on Relative Permeability Characteristics for CO2 in Sandstone under High Temperature and Overburden Pressure

In this study, CO2 seepage of sandstone samples from the Taiyuan-Shanxi Formation coal seam roof in Ordos Basin, China, under temperature-stress coupling was studied with the aid of the TAWD-2000 coal rock mechanics-seepage test system. Furthermore, the evolution law and influencing factors on permeability for CO2 in sandstone samples with temperature and axial pressure were systematically analyzed. The results disclose that the permeability of sandstone decreases with the increase in stress. The lower the stress is, the more sensitive the permeability is to stress variation. High stress results in a decrease in permeability, and when the sample is about to fail, the permeability surges. The permeability of sandstone falls first and then rises with the rise of temperature, which is caused by the coupling among the thermal expansion of sandstone, the desorption of CO2, and the evaporation of residual water in fractures. Finally, a quadratic function mathematical model with a fitting degree of 98.2% was constructed between the temperature-stress coupling effect and the permeability for CO2 in sandstone. The model provides necessary data support for subsequent numerical calculation and practical engineering application. The experimental study on the permeability characteristics for CO2 in sandstone under high temperature and overburden pressure is crucial for evaluating the storage potential and predicting the CO2 migration evolution in underground coal gasification coupling CO2 storage projects.

Analysis of Shale Oil Productivity Difference in an 83 and Xi 233 Well Blocks in Ordos Basin

The An 83 well block and the Xi 233 well block are both shale oil blocks in the Changqing Oilfield. The main producing layer is the Chang 7 reservoir, with strong heterogeneity and no obvious oil-water interface. Both are typical low porosity, Low permeability-extra low permeability reservoirs. The An 83 block and the Xi 233 block adopt the same volume modification method for production, but the output data of the two are quite different. The output of the Xi 233 block is significantly better than the An 83 block, and the water content is also lower. Finding out the reasons for the production differences and proposing a targeted shale oil reservoir volume modification model is the key to increasing the production of Block An 83. On the basis of the analysis of production influencing factors, it combines geological factors such as gamma, interval transit time, porosity, saturation, etc., geomechanical factors such as Young’s modulus, Poisson’s ratio, horizontal stress, and Engineering factors such as displacement, liquid volume, sand ratio, etc. Using Pearson and Spearman correlation analysis methods to clarify the main controlling factors of output and capacity, on this basis, complete the research on the output difference of the two blocks. The final results show that the physical properties of the two blocks are the same, the water content is quite different, and the geomechanical basis is different. It is necessary to formulate targeted reservoir transformation and production methods based on the pore throat structure, relative permeability and geomechanical distribution characteristics of Block An 83.

Electron-beam deposition of magneto-dielectric coatings in the forevacuum pressure range

We synthesized magneto-dielectric coatings in the pressure range of 1–10 Pa using sequential electron-beam evaporation of alumina ceramic and ferrite targets. The electron-beam evaporation of targets with low electrical conductivity is made possible due to the neutralization of the electrical charging of the targets by the beam plasma ions. We investigated the evolution of the mass-to-charge composition of plasma ions with increasing target temperature and measured the electrical (frequency dependencies of capacitance, dielectric loss angle and impedance) and magnetic (real and imaginary parts of the relative magnetic permeability) characteristics of the coatings.

Thermal comfort properties of weft knitted quilted fabrics

PurposeThis paper investigates the thermal comfort properties of quilted (jersey cord) fabrics produced with different width of diamond pattern, different filling yarn linear density and different types of material.Design/methodology/approachA total of 12 fabrics were knitted by varying the width of diamond pattern (1 and 3 cm), the filling yarn linear density (300 and 900 denier) and the type of materials (cotton, polyester and their combination). In this regard, air permeability, thermal conductivity, thermal resistance, thermal absorptivity and relative water vapor permeability of these fabrics were measured and evaluated statistically.FindingsThe results showed that fabrics knitted using cotton yarn in both front and back surfaces exhibit higher thermal conductivity, thermal absorptivity and relative water vapor permeability characteristics; whereas samples knitted using polyester yarn in both surfaces have higher air permeability and thermal resistance. As the linear density of filling yarn increases, thickness and thermal resistance of the samples increase and air permeability, thermal conductivity, water vapor permeability characteristics decrease. When the effect of the width of diamond pattern compared, it is seen that an increase in the width of pattern lead to an increase in thickness and thermal resistance and a decrease in thermal conductivity, thermal absorptivity and water vapor permeability values.Originality/valueMany researches were carried out on the thermal comfort properties of knitted fabrics, however there is a lack of research efforts regarding thermal comfort properties of quilted fabrics.

Relative Permeability Characteristics During Carbon Capture and Sequestration Process in Low-Permeable Reservoirs.

The injection of carbon dioxide (CO2) in low-permeable reservoirs can not only mitigate the greenhouse effect on the environment, but also enhance oil and gas recovery (EOR). For numerical simulation work of this process, relative permeability can help predict the capacity for the flow of CO2 throughout the life of the reservoir, and reflect the changes induced by the injected CO2. In this paper, the experimental methods and empirical correlations to determine relative permeability are reviewed and discussed. Specifically, for a low-permeable reservoir in China, a core displacement experiment is performed for both natural and artificial low-permeable cores to study the relative permeability characteristics. The results show that for immiscible CO2 flooding, when considering the threshold pressure and gas slippage, the relative permeability decreases to some extent, and the relative permeability of oil/water does not reduce as much as that of CO2. In miscible flooding, the curves have different shapes for cores with a different permeability. By comparing the relative permeability curves under immiscible and miscible CO2 flooding, it is found that the two-phase span of miscible flooding is wider, and the relative permeability at the gas endpoint becomes larger.

Relative Permeability Characteristics and Wetting Behavior of Supercritical CO2 Displacing Water and Remaining Oil for Carbonate Rocks at Reservoir Conditions

Relative permeability characteristic and wetting behavior of reservoir rocks are crucial for oil recovery. Supercritical CO2 (sc-CO2) miscible flooding as an enhanced oil recovery (EOR) method has ...

A further verification of FZI* and PSRTI: Newly developed petrophysical rock typing indices

Despite the differences between petrophysical static (PSRTs) and dynamic rock types (PDRTs), previous indices were unable to distinguish between them. FZI-Star (FZI*) and PSRTI are recently developed petrophysical dynamic and static rock typing indices, respectively. Considering the importance of rock typing in reservoir characterization and the need for reliable and user-friendly techniques, in this study we attempt to further verify the performance of FZI* and PSRTI by comparing them with FZI, Winland r35, and MFZI using data belonging to a heterogeneous carbonate reservoir from the Asmari Formation. The experimental data set includes 10 primary drainage mercury injection, 29 water-oil, and 45 gas-oil capillary pressure tests for PSRTs prediction in conjunction with 52 water-oil and 51 gas-oil relative permeability data for PDRTs. Moreover, we investigated the correlation between various indices and several petrophysical attributes. We defined these attributes as the integrals of mercury injection capillary pressure, mercury injection threshold capillary pressure, measured r35, capillary pressure, and relative permeability curves along with residual saturations. The results showed that our indices are able to successfully identify static and dynamic rock units with higher accuracy than other indices. Among the other existing methods, Winland r35 was the only one that showed an acceptable outcome; while, FZI, and MFZI underperformed in identifying the existing rock types. Using the experimental data we also propose the empirical equations that can be used to model capillary pressure and relative permeability characteristics of rocks.

Experimental investigation into the relative permeability of gas and water in low-rank coal

Understanding the relative permeability characteristics of coal in a gas-water system is crucial for coalbed methane development. Due to a lack of experimental information on the gas-water relative permeability of coal, the relative permeability of the low-rank coals in the Erlian Basin in the north of China was investigated under different conditions using the unsteady-state method. The studied coals are dominated by huminite with high moisture content, volatile yield, and low ash yield. The pore sizes of the coals feature a bimodal pattern distribution with a higher left peak of approximately 10–100 nm and a relatively lower right peak of approximately 10000 nm. The measurement of mercury intrusion-extrusion hysteresis also suggests that ink bottle-shaped pores are possibly developed within the coals. The results from relative permeability tests with methane (CH4) and water depend on the pore structure, coal wettability, confining pressure, and pressure difference in the coal. The results show that a definite correlation does not exist between relative permeability and porosity in the low-rank coal. However, macropore porosity rather than the whole range of the porosity is the most likely property affecting the water relative permeability, whereas the effect of pore size on gas relative permeability varies along with a broader range. It has been observed that the low-rank coal with higher water wettability exhibits lower water relative permeability, narrower two-phase span, higher gas relative permeability, and irreducible water saturation. With the increase in the confining pressure, both the methane and water relative permeabilities decrease, while the ratio of relative permeability (krw/krg) increases. This suggests that the confining pressure has less influence on water relative permeability than that on gas. As the pressure difference increases under the same effective stress, the residual water saturation in the low-rank coals decreases, and the associated two-phase span increases. Water relative permeability obviously increases above the crossover point water saturation, whereas gas relative permeability increases below the crossover point water saturation.

A CUSTOMIZED QUASI THREE-PHASE DRAINAGE RELATIVE PERMEABILITY MODEL FOR SOME INDONESIAN WATER-WET SANDSTONES

Information about drainage effective two-phase i.e. quasi three-phase relative permeability characteristics of reservoir rocks is regarded as very important in hydrocarbon reservoir modeling. The data governs various processes in reservoir such as gas cap expansion, solution gas expansion, and immiscible gas drive in enhanced oil recovery (EOR). The processes are mechanisms in reservoir that in the end determines reserves and resevoir production performance. Nevertheless, the required information is often unavailable for various reasons. This study attempts to provide solution through customizing an existing drainage relative permeability model enabling it to work for Indonesian reservoir rocks. The standard and simple Corey et al. relative permeability model is used to model 32 water-wet sandstones taken from 5 oil wells. The sandstones represent three groups of conglomeratic sandstones, micaceous-argillaceous sandstones, and hard sandstones. Special correlations of permeability irreducible water saturation and permeability ratio irreducible water saturation have also been established. Model applications on the 32 sandstones have yielded specific pore size distribution index (?) and wetting phase saturation parameter (Sm) values for the three sandstone groups, and established a practical procedure for generating drainage quasi three-phase relative permeability curves in absence of laboratory direct measurement data. Other findings such as relations between ? and permeability and influence of sample size in the modeling are also made.

Study on the rock-electric and the relative permeability characteristics in porous rocks based on the curved cylinder-sphere model

Usually, in conventional reservoirs, the rock-electric properties can be explained by Archie's law, and the relative permeability is only considered as a function of fluid saturation. However, as for the complex reservoirs, Archie's law fails to accurately describe the rock-electric properties and the relative permeability is not only affected by saturation, the reason is that both rock-electric and relative permeability characteristics are influenced by multi-factors, including the complex pore structure, fluid distribution, and wettability. Currently, there lacks the theoretical method to comprehensively study the multi-factors effect on rock-electric and relative permeability characteristics. In this paper, the curved cylinder-sphere model is developed to illustrate the complex pore-throat structure, fluid distribution, and wettability in real rocks, which can be characterized by two important parameters: the ratio Cd of the curved cylinder radius to the sphere radius and the tortuosity τ. Based on the curved cylinder-sphere model, and by using Ohm's law, one can carry out the research on the effect of pore geometry, fluid distribution, and wettability on rock-electric characteristics. Moreover, by combining the curved cylinder-sphere model with Li's model, the effect of pore structure, fluid distribution, and wettability can be incorporated into the relative permeability calculation model. By means of the numerical simulation and analysis, it comes to conclusions that pore structure, fluid distribution, and wettability are the principal factors affecting both rock-electric and relative permeability characteristics, which may cause different formation factor, resistivity index, and relative permeability even in those reservoirs with the same porosity and fluid saturation. Besides, the study demonstrates that the complex pore structure, fluid distribution, and wettability may cause the non-Archie phenomenon of rock-electric characteristics, in addition, the complex pore structure can lead to the decrease of water relative permeability and the increase of oil relative permeability, and when the rock wettability changes from water-wet to oil-wet, water relative permeability increases and oil relative permeability decreases. Furthermore, by the comparison of the simulation results and Lab data, the important effect of complex pore structure and fluid saturation is confirmed.