scholarly journals Interpretation of Gas/Water Relative Permeability of Coal Using the Hybrid Bayesian-Assisted History Matching: New Insights

Energies ◽  
2021 ◽  
Vol 14 (3) ◽  
pp. 626
Author(s):  
Jiyuan Zhang ◽  
Bin Zhang ◽  
Shiqian Xu ◽  
Qihong Feng ◽  
Xianmin Zhang ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Coalbed Methane ◽  
History Matching ◽  
Water Saturation ◽  
Unsteady State ◽  
Core Flooding ◽  
Rock Interaction ◽  
Interaction Mechanisms ◽  
True Value ◽  
Assisted History Matching

The relative permeability of coal to gas and water exerts a profound influence on fluid transport in coal seams in both primary and enhanced coalbed methane (ECBM) recovery processes where multiphase flow occurs. Unsteady-state core-flooding tests interpreted by the Johnson–Bossler–Naumann (JBN) method are commonly used to obtain the relative permeability of coal. However, the JBN method fails to capture multiple gas–water–coal interaction mechanisms, which inevitably results in inaccurate estimations of relative permeability. This paper proposes an improved assisted history matching framework using the Bayesian adaptive direct search (BADS) algorithm to interpret the relative permeability of coal from unsteady-state flooding test data. The validation results show that the BADS algorithm is significantly faster than previous algorithms in terms of convergence speed. The proposed method can accurately reproduce the true relative permeability curves without a presumption of the endpoint saturations given a small end-effect number of <0.56. As a comparison, the routine JBN method produces abnormal interpretation results (with the estimated connate water saturation ≈33% higher than and the endpoint water/gas relative permeability only ≈0.02 of the true value) under comparable conditions. The proposed framework is a promising computationally effective alternative to the JBN method to accurately derive relative permeability relations for gas–water–coal systems with multiple fluid–rock interaction mechanisms.

scholarly journals Insights, Trends and Challenges Associated with Measuring Coal Relative Permeability

2019 ◽  
Vol 89 ◽  
pp. 01004
Author(s):  
Dylan Shaw ◽  
Peyman Mostaghimi ◽  
Furqan Hussain ◽  
Ryan T. Armstrong
Keyword(s):  
Relative Permeability ◽  
Effective Stress ◽  
History Matching ◽  
Water Saturation ◽  
Laboratory Data ◽  
Stress Regime ◽  
Cross Point ◽  
Irreducible Water Saturation ◽  
Relative Permeability Curves ◽  
The Right

Due to the poroelasticity of coal, both porosity and permeability change over the life of the field as pore pressure decreases and effective stress increases. The relative permeability also changes as the effective stress regime shifts from one state to another. This paper examines coal relative permeability trends for changes in effective stress. The unsteady-state technique was used to determine experimental relativepermeability curves, which were then corrected for capillary-end effect through history matching. A modified Brooks-Corey correlation was sufficient for generating relative permeability curves and was successfully used to history match the laboratory data. Analysis of the corrected curves indicate that as effective stress increases, gas relative permeability increases, irreducible water saturation increases and the relative permeability cross-point shifts to the right.

Effect of Interfacial Tension on Water/Oil Relative Permeability on the Basis of History Matching to Coreflood Data

2014 ◽  
Vol 17 (01) ◽  
pp. 37-48 ◽  
Author(s):  
Edwin Andrew Chukwudeme ◽  
Ingebret Fjelde ◽  
Kumuduni Abeysinghe ◽  
Arild Lohne
Keyword(s):  
Interfacial Tension ◽  
Relative Permeability ◽  
Capillary Number ◽  
History Matching ◽  
Water Saturation ◽  
Residual Water ◽  
End Effects ◽  
The Core ◽  
Rate Dependent ◽  
Phase Saturation

Summary The effect of interfacial tension (IFT) on the displacement of the nonwetting and wetting phases has been investigated by the use of simulations/history matching of flooding experiments. In surfactant flooding, a conventional assumption is to neglect the effect of capillary pressure (Pc) on measured two-phase properties. The methodology applied in this paper allows improved interpretation of experimental results by correcting for the influence of capillary end effects on the measured capillary desaturation curve (CDC) and on the estimated relative permeability (kr). Three fluid systems of different IFTs were prepared by use of a solvent system (CaCl2 brine/iso-octane/isopropanol) rather than a surfactant system with the assumption that both systems have similar flood behavior at reduced IFT. Three coreflood cycles, including multirate oil injection (drainage) followed by multirate water injection (imbibition), were carried out at each IFT in water-wet Berea cores. The kr functions corrected for capillary end effects were derived by numerically history matching the experimental production and pressure-drop (PD) history. A typical CDC is observed for the nonwetting phase oil, with a roughly constant plateau in residual oil saturation (ROS), Sor, below a critical capillary number (Ncc) and a declining slope above Ncc toward zero Sor. No influence of Pc was found for the nonwetting-phase CDC. The results from the displacement of the wetting phase formed an apparent CDC with a declining slope and no Ncc. Analyzing the wetting-phase results, we find that the wetting-phase CDC is not a true CDC. First, it is a plot of the average remaining water saturation (Sw) in the core which, in all the experiments, is higher than residual water saturation, Swr, obtained from Pc measurements. Second, we find that the remaining Sw is only partly a function of Nc. At low Nc, the water production (WP) is limited by capillary end effects. Rate-dependent WP observed with the high-IFT system is fully reproduced in simulations by use of constant kr and Pc. The remaining wetting-phase saturation at a low capillary number (Nc) is a result of the core-scale balance between viscous and capillary forces and would, for example, depend on the core length. At a higher Nc, the WP is found to be limited by the low kr tail, typical for wetting phases. However, we find that the kr functions become rate dependent at a higher Nc, and we assume that this rate dependency can be modeled as a function of Nc. The remaining wetting-phase saturation at a higher Nc would then be a function of Nc and the number of pore volumes (PVs) injected. The observed Nc dependency in the flow functions indicates a potential for the accelerated production of the wetting phase by use of surfactant. Assuming that the results obtained here for the wetting phase also apply to oil in a mixed-wet system, it is strongly recommended to evaluate the effect of both Pc and Ncc when designing a surfactant model for a mixed-wet field.

scholarly journals The Numerical Simulation Study of the Oil–Water Seepage Behavior Dependent on the Polymer Concentration in Polymer Flooding

Energies ◽  
2020 ◽  
Vol 13 (19) ◽  
pp. 5125
Author(s):  
Qiong Wang ◽  
Xiuwei Liu ◽  
Lixin Meng ◽  
Ruizhong Jiang ◽  
Haijun Fan
Keyword(s):  
Relative Permeability ◽  
History Matching ◽  
Polymer Concentration ◽  
Polymer Flooding ◽  
Core Flooding ◽  
Relative Permeability Curve ◽  
Oil Water ◽  
Trapping Number ◽  
Relative Permeability Curves ◽  
Interpolation Factor

It is well acknowledged that due to the polymer component, the oil–water relative permeability curve in polymer flooding is different from the curve in waterflooding. As the viscoelastic properties and the trapping number are presented for modifying the oil–water relative permeability curve, the integration of these two factors for the convenience of simulation processes has become a key issue. In this paper, an interpolation factor Ω that depends on the normalized polymer concentration is firstly proposed for simplification. Then, the numerical calculations in the self-developed simulator are performed to discuss the effects of the interpolation factor on the well performances and the applications in field history matching. The results indicate that compared with the results of the commercial simulator, the simulation with the interpolation factor Ω could more accurately describe the effect of the injected polymer solution in controlling water production, and more efficiently simplify the combination of factors on relative permeability curves in polymer flooding. Additionally, for polymer flooding history matching, the interpolation factor Ω is set as an adjustment parameter based on core flooding results to dynamically consider the change of the relative permeability curves, and has been successfully applied in the water cut matching of the two wells in Y oilfield. This investigation provides an efficient method to evaluate the seepage behavior variation of polymer flooding.

scholarly journals Laboratory Measurements of the Relative Permeability of Coal: A Review

Energies ◽  
2020 ◽  
Vol 13 (21) ◽  
pp. 5568
Author(s):  
Shaicheng Shen ◽  
Zhiming Fang ◽  
Xiaochun Li
Keyword(s):  
Carbon Dioxide ◽  
Relative Permeability ◽  
Coalbed Methane ◽  
Water Saturation ◽  
Gas Production ◽  
Absolute Permeability ◽  
Permeability Measurement ◽  
Mixed Gas ◽  
Practical Engineering ◽  
Relative Permeability Curves

The relative permeability of coal to gas and water is an essential parameter for characterizing coalbed methane (CBM) reservoirs and predicting coal seam gas production, particularly in numerical simulations. Although a variety of studies related to the relative permeability of coals have been conducted, the results hardly meet the needs of practical engineering applications. To track the dynamic development of relative permeability measurements in the laboratory, discover the deficiencies, and discuss further work in this field, this paper investigates the relative permeability measurement preparation work and laboratory methods and summarizes the development of techniques used to determine the water saturation during experimentation. The previously determined relative permeability curves are also assembled and classified according to coal rank and the absolute permeability. It is found that the general operations in the relative permeability measurement process are still not standardized. The techniques applied to determine the water saturation of coal in experiments have been refined to some extent, but no optimal technique has been recognized yet. New techniques, such as the incorporation of high-precision differential pressure gauges, can be used to determine the water production during relative permeability measurement. In addition, the existing relative permeability data are limited, and no study has focused on supercritical carbon dioxide-water and mixed gas (methane and carbon dioxide)-water relative permeability measurements. To meet the requirements of actual projects, further research on this topic must be conducted.

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