Simultaneous Estimation of Relative Permeability and Capillary Pressure for Tight Formations from Displacement Experiments

2012 ◽  
Author(s):  
Yin Zhang ◽  
Chengyao Song ◽  
Sixu Zheng ◽  
Daoyong Tony Yang
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Simultaneous Estimation ◽  
Displacement Experiments ◽  
Tight Formations

Using relative permeability curves to evaluate phase trapping damage caused by water- and oil-based drilling fluids in tight-gas reservoirs

2012 ◽  
Vol 52 (1) ◽  
pp. 595 ◽  
Author(s):  
Geeno Murickan ◽  
Hassan Bahrami ◽  
Reza Rezaee ◽  
Ali Saeedi ◽  
Tsar Mitchel
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Drilling Fluid ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Tight Gas Reservoirs ◽  
Water Based ◽  
Tight Formations ◽  
Relative Permeability Curves ◽  
Tight Formation

Low matrix permeability and significant damage mechanisms are the main signatures of tight-gas reservoirs. During the drilling and fracturing of tight formations, the wellbore liquid invades the tight formation, increases liquid saturation around the wellbore, and eventually reduces permeability at the near wellbore zone. The liquid invasion damage is mainly controlled by capillary pressure and relative permeability curves. Due to high critical water saturation, relative permeability effects and strong capillary pressure, tight formations are sensitive to water invasion damage, making water blocking and phase trapping damage two of the main concerns with using a water-based drilling fluid in tight-gas reservoirs.Therefore, the use of an oil-based mud may be preferred in the drilling or fracturing of a tight formation. Invasion of an oil filtrate into tight formations, however, may result in the introduction of an immiscible liquid-hydrocarbon drilling or completion fluid around the wellbore, causing the entrapment of an additional third phase in the porous media that would exacerbate formation damage effects. This study focuses on phase trapping damage caused by liquid invasion using a water-based drilling fluid in comparison with the use of an oil-based drilling fluid in water-sensitive, tight-gas sand reservoirs. Reservoir simulation approach is used to study the effect of relative permeability curves on phase trap damage, and the results of laboratory experiments of core flooding tests in a West Australian tight-gas reservoir are shown, where the effect of water injection and oil injection on the damage of core permeability are studied. The results highlight the benefits of using oil-based fluids in drilling and fracturing of tight-gas reservoirs in terms of reducing skin factor and improving well productivity.

Simultaneous Estimation of Relative Permeability and Capillary Pressure for PUNQ-S3 Model With a Damped Iterative-Ensemble-Kalman-Filter Technique

SPE Journal ◽  
2017 ◽  
Vol 22 (03) ◽  
pp. 971-984 ◽  
Author(s):  
Yin Zhang ◽  
Zhaoqi Fan ◽  
Daoyong Yang ◽  
Heng Li ◽  
Shirish Patil
Keyword(s):  
Kalman Filter ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Ensemble Kalman Filter ◽  
History Matching ◽  
Simultaneous Estimation ◽  
Reservoir Models ◽  
Ensemble Smoother ◽  
Iterative Ensemble Smoother ◽  
Capillary Pressure Curves

Summary A damped iterative-ensemble-Kalman-filter (IEnKF) algorithm has been proposed to estimate relative permeability and capillary pressure curves simultaneously for the PUNQ-S3 model, while its performance has been compared with that of the CMOST module, iterative-ensemble-smoother (IES) algorithm, and traditional ensemble-Kalman-filter (EnKF) technique. The power-law model is used to represent the relative permeability and capillary pressure curves, while three-phase relative permeability for oil phase is determined by use of the modified Stone II model. By assimilating the observed production data, the relative permeability and capillary pressure curves are inversely, automatically, and successively updated, achieving an excellent agreement with the reference cases. Not only are the associated uncertainties reduced significantly during the updating process, but also each of the updated reservoir models predicts the production profile that is in good agreement with the reference cases. Although the damped IEnKF technique shows the highest accuracy on estimation results, history-matching results, and prediction performance for the PUNQ-S3 model, its computational expense is still high compared with the other three techniques. In addition, the variations in the ensemble of the updated reservoir models and production profiles of the damped IEnKF provide a robust and consistent framework for uncertainty analysis.

Three-Phase Relative Permeabilities from Displacement Experiments with Full Account for Capillary Pressure

1998 ◽  
Vol 1 (02) ◽  
pp. 92-98 ◽  
Author(s):  
H.M. Helset ◽  
J.E. Nordtvedt ◽  
S.M. Skjaeveland ◽  
G.A. Virnovsky
Keyword(s):  
Porous Media ◽  
Multiphase Flow ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Single Phase ◽  
Flow In Porous Media ◽  
Relative Permeabilities ◽  
The Core ◽  
Three Phase ◽  
Displacement Experiments

Abstract Relative permeabilities are important characteristics of multiphase flow in porous media. Displacement experiments for relative permeabilities are frequently interpreted by the JBN method neglecting capillary pressure. The experiments are therefore conducted at high flooding rates, which tend to be much higher than those experienced during reservoir exploitation. Another disadvantage is that the relative permeabilities only can be determined for the usually small saturation interval outside the shock. We present a method to interpret displacement experiments with the capillary pressure included, using in-situ measurements of saturations and phase pressures. The experiments can then be run at low flow rates, and relative permeabilities can be determined for all saturations. The method is demonstrated by using simulated input data. Finally, experimental scenarios for three-phase displacement experiments are analyzed using experimental three-phase relative permeability data. Introduction Relative permeabilities are important characteristics of multiphase flow in porous media. These quantities arise from a generalization of Darcy's law, originally defined for single phase flow. Relative permeabilities are used as input to simulation studies for predicting the performance of potential strategies for hydrocarbon reservoir exploitation. The relative permeabilities are usually determined from flow experiments performed on core samples. The most direct way to measure the relative permeabilities is by the steady-state method. Each experimental run gives only one point on the relative permeability curve (relative permeability vs. saturation). To make a reasonable determination of the whole curve, the experiment has to be repeated at different flow rate fractions. To cover the saturation plane in a three-phase system, a large number of experiments have to be performed. The method is therefore very time consuming. Relative permeabilities can also be calculated from a displacement experiment. Typically, the core is initially saturated with a single-phase fluid. This phase is then displaced by injecting the other phases into the core. For the two-phase case, Welge showed how to calculate the ratio of the relative permeabilities from a displacement experiment. Efros was the first to calculate individual relative permeabilities from displacement experiments. Later, Johnson et al. presented the calculation procedure in a more rigorous manner, and the method is often referred to as the JBN method. The analysis has also been extended to three phases. In this approach, relative permeabilities are calculated at the outlet end of the core; saturations vs. time at the outlet end is determined from the cumulative volumes produced and time derivatives of the cumulative volumes produced, and relative permeabilities vs. time are calculated from measurements of pressure drop over the core and the time derivative of the pressure drop. Although the JBN method is frequently used for relative permeability determination, it has several drawbacks. The method is based on the Buckley-Leverett theory of multiphase flow in porous media. The main assumption is the neglection of capillary pressure. In homogenous cores capillary effects are most important at the outlet end of the core and over the saturation shock front. To suppress capillary effects, the experiments are performed at a high flow rate. Usually, these rates are significantly higher than those experienced in the underground reservoirs during exploitation.

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