scholarly journals Research on the Relationship between Electrical Parameters and Relative Permeability of Tight Sandstone

ACS Omega ◽  
2022 ◽  
Author(s):  
Ting Zhao ◽  
Yabin He ◽  
Li Song ◽  
Xiao Li ◽  
Xiaojuan Chen
Keyword(s):  
Relative Permeability ◽  
Electrical Parameters ◽  
Tight Sandstone ◽  
The Relationship

scholarly journals Productivity Influence Factors of Tight Sandstone Gas Reservoir with Water Produced

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Yongchao Xue ◽  
Qingshuang Jin ◽  
Hua Tian
Keyword(s):  
Pressure Gradient ◽  
Relative Permeability ◽  
Gas Flow ◽  
Influence Factors ◽  
Stress Sensitivity ◽  
Consumption Pattern ◽  
Tight Sandstone ◽  
Gas Reservoir ◽  
Two Phase ◽  
Start Up

Finding ways to accelerate the effective development of tight sandstone gas reservoirs holds great strategic importance in regard to the improvement of consumption pattern of world energy. The pores and throats of the tight sandstone gas reservoir are small with abundant interstitial materials. Moreover, the mechanism of gas flow is highly complex. This paper is based on the research of a typical tight sandstone gas reservoir in Changqing Oilfield. A strong stress sensitivity in tight sandstone gas reservoir is indicated by the results, and it would be strengthened with the water production; at the same time, a rise to start-up pressure gradient would be given by the water producing process. With the increase in driving pressure gradient, the relative permeability of water also increases gradually, while that of gas decreases instead. Following these results, a model of gas-water two-phase flow has been built, keeping stress sensitivity, start-up pressure gradient, and the change of relative permeability in consideration. It is illustrated by the results of calculations that there is a reduction in the duration of plateau production period and the gas recovery factor during this period if the stress sensitivity and start-up pressure gradient are considered. In contrast to the start-up pressure gradient, stress sensitivity holds a greater influence on gas well productivity.

scholarly journals Study on Water Displacing Gas Relative Permeability Curves in Fractured Tight Sandstone Reservoirs Under High Pressure and High Temperature

ACS Omega ◽  
2020 ◽  
Vol 5 (13) ◽  
pp. 7456-7461
Author(s):  
Jianfen Du ◽  
Qi Liu ◽  
Ping Guo ◽  
Tongwen Jiang ◽  
Yuming Xiong ◽  
...  
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Relative Permeability ◽  
Tight Sandstone ◽  
Sandstone Reservoirs ◽  
Relative Permeability Curves

Estimating the Relative Permeability from the Electrical Parameters of Sandstone with a Complex Pore Structure

2020 ◽  
Vol 34 (11) ◽  
pp. 14124-14131
Author(s):  
Weibiao Xie ◽  
Qiuli Yin ◽  
Wei Guan ◽  
Guiwen Wang ◽  
Jin Lai
Keyword(s):  
Pore Structure ◽  
Relative Permeability ◽  
Electrical Parameters

The Resistive-Acoustic Method of Monitoring Industrial Sludge Plume

2015 ◽  
Vol 770 ◽  
pp. 679-685 ◽  
Author(s):  
Artem Bykov ◽  
Oleg Kuzichkin ◽  
Nikolay Dorofeev
Keyword(s):  
Soil Moisture Content ◽  
Acoustic Method ◽  
Acoustic Monitoring ◽  
Practical Application ◽  
Electrical Parameters ◽  
Monitoring Method ◽  
Industrial Sludge ◽  
Current Frequency ◽  
Energy Complex ◽  
The Relationship

The paper deals with the resistive-acoustic monitoring method for early industrial spill detection on fuel and energy complex sites. The paper analyzes major indirect geophysical techniques used for oil plume detection. The scientific grounds for the application of the resistive-acoustic monitoring method are given. The paper considers the possibility of spotting medium non-uniformity by means of total resistance registration with the site non-uniformity localization due to seismic-acoustic effects. The relationship between soil electrical parameters and electric current frequency at varying soil moisture content is presented. Practical application of the resistive-acoustic method for oil-sludge spill monitoring on fuel and energy complex sites is described.

Measurements of Relative Permeabilities for Calculating Gas-Condensate Well Deliverability

2000 ◽  
Vol 3 (06) ◽  
pp. 473-479 ◽  
Author(s):  
R.E. Mott ◽  
A.S. Cable ◽  
M.C. Spearing
Keyword(s):  
Relative Permeability ◽  
Capillary Number ◽  
Gas Condensate ◽  
Relative Permeabilities ◽  
Well Productivity ◽  
Gas Condensate Reservoirs ◽  
Liquid Saturation ◽  
Condensate Reservoir ◽  
Deep Reservoir ◽  
The Relationship

Summary Well deliverability in many gas-condensate reservoirs is reduced by condensate banking when the bottomhole pressure falls below the dewpoint, although the impact of condensate banking may be reduced due to improved mobility at high capillary number in the near-well region. This paper presents the results of relative permeability measurements on a sandstone core from a North Sea gas-condensate reservoir, at velocities that are typical of the near-well region. The results show a clear increase in mobility with capillary number, and the paper describes how the data can be modeled with empirical correlations which can be used in reservoir simulators. Introduction Well deliverability is an important issue in the development of many gas-condensate reservoirs, especially where permeability is low. When the well bottomhole flowing pressure falls below the dewpoint, condensate liquid may build up around the wellbore, causing a reduction in gas permeability and well productivity. In extreme cases the liquid saturation may reach values as high as 50 or 60% and the well deliverability may be reduced by up to an order of magnitude. The loss in productivity due to this "condensate banking" effect may be significant, even in very lean gas-condensate reservoirs. For example, in the Arun reservoir,1 the productivity reduced by a factor of about 2 as the pressure fell below the dewpoint, even though the reservoir fluid was very lean with a maximum liquid drop out of only 1% away from the well. Most of the pressure drop from condensate blockage occurs within a few feet of the wellbore, where velocities are very high. There is a growing body of evidence from laboratory coreflood experiments to suggest that gas-condensate relative permeabilities increase at high velocities, and that these changes can be correlated against the capillary number.2–8 The capillary number is a dimensionless number that measures the relative strength of viscous and capillary forces. There are several gas-condensate fields where simulation with conventional relative permeability models has been found to underestimate well productivity.1,9,10 To obtain a good match between simulation results and well-test data, it was necessary to increase the mobility in the near-well region, either empirically or through a model of the increase in relative permeability at high velocity. This effect can increase well productivity significantly, and in some cases may eliminate most of the effect of condensate blockage. Experimental Data Requirements Fevang and Whitson11 have shown that the key parameter in determining well deliverability is the relationship between krg and the ratio krg/ kro. When high-velocity effects are significant, the most important information is the variation of krg with krg/k ro and the capillary number Nc. The relevant values of krg/kro are determined by the pressure/volume/temperature (PVT) properties of the reservoir fluids, but typical values might be 10 to 100 for lean condensates, 1 to 10 for rich condensates, and 0.1 to 10 for near-critical fluids. There are various ways of defining the capillary number, but in this paper we use the definition (1)Nc=vgμgσ, so that the capillary number is proportional to the gas velocity and inversely proportional to interfacial tension (IFT). The capillary numbers that are relevant for well deliverability depend on the flow rate, fluid type, and well bottomhole pressure, but as a general rule, values between 10?6 and 10?3 are most important. Experimental Methods In a gas-condensate reservoir, there are important differences between the flow regimes in the regions close to and far from the well. These different flow regimes are reflected in the requirements for relative permeability data for the deep reservoir and near-well regions. Far from the well, velocities are low, and liquid mobility is usually less important, except in reservoirs containing very rich fluids. In the near-well region, both liquid and gas phases are mobile, velocities are high, and the liquid mobility is important because of its effect on the relationship between krg and krg/kro. Depletion Method. Relative permeabilities for the deep reservoir region are often measured in a coreflood experiment, where the fluids in the core are obtained by a constant volume depletion (CVD) on a reservoir fluid sample. Relative permeabilities are measured at decreasing pressures from the fluid dewpoint, and increasing liquid saturation. In this type of experiment, the liquid saturation cannot exceed the critical condensate saturation or the maximum value in a CVD experiment, so that it is not possible to acquire data at the high liquid saturations that occur in the reservoir near to the well. The "depletion" experiment provides relative permeability data that are relevant to the deep reservoir, but there can be problems in interpreting the results due to the effects of IFT. Changes in liquid saturation are achieved by reducing pressure, which results in a change of IFT. The increase in IFT as pressure falls may cause a large reduction in mobility, and Chen et al.12 describe an example where the condensate liquid relative permeability decreases with increasing liquid saturation. Steady-State Method. The steady-state technique can be used to measure relative permeabilities at the higher liquid saturations that occur in the near-well region. Liquid and gas can be injected into the core from separate vessels, allowing relative permeabilities to be measured for a wide range of saturations. Results of gas-condensate relative permeabilities measured by this technique have been reported by Henderson et al.2,6 and Chen et al.12 .

The Simulated Calculation of the First Order Buoyancy Force under Different Relative Permeability of Ferrofluid

2013 ◽  
Vol 303-306 ◽  
pp. 22-25 ◽  
Author(s):  
Qiang Li ◽  
Zuo Bin Yuan ◽  
Yong Ming Yang ◽  
Cheng Hu
Keyword(s):  
Magnetic Field ◽  
External Magnetic Field ◽  
Relative Permeability ◽  
Buoyancy Force ◽  
First Order ◽  
Simulated Calculation ◽  
The Relationship

In this paper, the first order buoyancy force of ferrofluid is simulated calculation under external magnetic field in ferrofluid devices. The relationship between first order buoyancy force and displacement of nonmagnetic body under different relative permeability of ferrofluid，and the relationship between first order buoyancy force and relative permeability of ferrofluid are obtained.

scholarly journals Study on the relationship between the water cutting rate and the remaining oil saturation of the reservoir by using the index percolating saturation formula with variable coefficients

2020 ◽  
Vol 10 (8) ◽  
pp. 3649-3661
Author(s):  
Meiling Zhang ◽  
Jiayi Fan ◽  
Yongchao Zhang ◽  
Yinxin Liu
Keyword(s):  
Relative Permeability ◽  
Water Saturation ◽  
Variable Coefficients ◽  
Absolute Permeability ◽  
Oil Saturation ◽  
Rock Samples ◽  
Remaining Oil ◽  
Cutting Rate ◽  
Water Cutting ◽  
The Relationship

Abstract The water cutting rate is recorded dynamically during the production process of a well. If the remaining oil saturation of the reservoir can be deduced based on the water cutting rate, it will give guidance to improve the reservoir recovery and can save expensive drilling costs. In the oil–water two-phase seepage experiment on core samples, the oil and water relative permeability reflects the relationship between the water cutting rate and water saturation, that is, percolating saturation formula. The relative permeability test data of 17 rock samples from six seal coring wells in Daqing Changyuan were used to optimize and construct the coefficients of the index percolating saturation formula that vary with the pore structure parameters of reservoirs, to form an index percolating saturation formula with variable coefficients that is more consistent with the regional geological characteristics of the reservoir. Based on this, the formula of water saturation calculated by the water cutting rate is deduced. And the high-precision formula for calculating the irreducible water saturation and residual oil saturation by effective porosity, absolute permeability, and shale content is given. The derivative formula of water saturation on the water cutting rate was established, and the parameters of 17 rock samples were calculated. It was found that the variation velocity of water saturation of each sample with the water cutting rate presented a “U” shape, which was consistent with the actual characteristics that the variation velocity of the water saturation in the early, middle, and late stages of oilfield development first decreased, then stabilized, and finally increased rapidly. The research results were applied to the prediction of remaining oil saturation in the research area, and the water saturation about six producing wells was calculated by using their present water cutting rates, and the remaining oil distribution profile was predicted effectively. The analysis of four layers of two newly drilled infill wells and reasonable oil recovery suggestions were given to achieve good results.

scholarly journals Diagenesis and its influence on reservoir quality and oil-water relative permeability: A case study in the Yanchang Formation Chang 8 tight sandstone oil reservoir, Ordos Basin, China

2019 ◽  
Vol 11 (1) ◽  
pp. 37-47 ◽  
Author(s):  
Meng Wang ◽  
Zhaomeng Yang ◽  
Changjun Shui ◽  
Zhong Yu ◽  
Zhufeng Wang ◽  
...  
Keyword(s):  
Pore Structure ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Ordos Basin ◽  
Reservoir Quality ◽  
Tight Oil ◽  
Property A ◽  
Tight Sandstone ◽  
Yanchang Formation ◽  
Small Pore

Abstract Different from conventional reservoirs, unconventional tight sand oil reservoirs are characterized by low or ultra-low porosity and permeability, small pore-throat size, complex pore structure and strong heterogeneity. For the continuous exploration and enhancement of oil recovery from tight oil, further analysis of the origins of the different reservoir qualities is required. The Upper Triassic Chang 8 sandstone of the Yanchang Formation from the Maling Oilfield is one of the major tight oil bearing reservoirs in the Ordos Basin. Practical exploration demonstrates that this formation is a typical tight sandstone reservoir. Samples taken from the oil layer were divided into 6 diagenetic facies based on porosity, permeability and the diagenesis characteristics identified through thin section and scanning electron microscopy. To compare pore structure and their seepage property, a high pressure mercury intrusion experiments (HPMI), nuclear magnetic resonance (NMR), andwater-oil relative permeability test were performed on the three main facies developed in reservoir. The reservoir quality and seepage property are largely controlled by diagenesis. Intense compaction leads to a dominant loss of porosity in all sandstones, while different degrees of intensity of carbonate cementation and dissolution promote the differentiation of reservoir quality. The complex pore structure formed after diagenesis determines the seepage characteristics, while cementation of chlorite and illite reduce the effective pore radius, limit fluid mobility, and lead to a serious reduction of reservoir permeability.

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