Effect of Capillary Number and Its Constituents on Two-Phase Relative Permeability Curves

1985 ◽  
Vol 37 (02) ◽  
pp. 249-260 ◽  
Author(s):  
R.A. Fulcher ◽  
Turgay Ertekin ◽  
C.D. Stahl
Keyword(s):  
Relative Permeability ◽  
Capillary Number ◽  
Two Phase ◽  
Relative Permeability Curves

Estimating Productivity-Controlling Parameters in Gas/Condensate Wells From Transient Pressure Data

2007 ◽  
Vol 10 (02) ◽  
pp. 100-111 ◽  
Author(s):  
Manijeh Bozorgzadeh ◽  
Alain C. Gringarten
Keyword(s):  
Relative Permeability ◽  
Capillary Number ◽  
Gas Condensate ◽  
Absolute Permeability ◽  
Well Test ◽  
Well Test Analysis ◽  
Two Phase ◽  
Well Productivity ◽  
Gas Condensate Reservoirs ◽  
Relative Permeability Curves

Summary The ability to predict well deliverability is a key issue for the development of gas/condensate reservoirs. We show in this paper that well deliverability depends mainly on the gas relative permeabilities at both the endpoint and the near-wellbore saturations, as well as on the reservoir permeability. We then demonstrate how these parameters and the base capillary number can be obtained from pressure-buildup data by using single-phase and two-phase pseudopressures simultaneously. These parameters can in turn be used to estimate gas relative permeability curves. Finally, we illustrate this approach with both simulated pressure-buildup data and an actual field case. Introduction and Background In gas/condensate reservoirs, a condensate bank forms around the wellbore when the bottomhole pressure (BHP) falls below the dewpoint pressure. This creates three different saturation zones around the well. Close to the wellbore, high condensate saturation reduces the effective permeability to gas, resulting in severe well productivity decline (Kniazeff and Nvaille 1965; Afidick et al. 1994; Lee and Chaverra 1998; Jutila et al. 2001; Briones et al. 2002). This decline is reduced at high gas rates and/or low capillary forces, which lower condensate saturation in the immediate vicinity of the wellbore, resulting in a corresponding increase in the gas relative permeability. This is called the capillary-number effect, positive coupling, viscous stripping, or velocity stripping (Boom et al. 1995; Henderson et al. 1998, 2000a; Ali et al. 1997a; Blom et al. 1997). High gas rates, on the other hand, induce inertia (also referred to as turbulent or non-Darcy flow effects), which reduces productivity. Well productivity is thus a balance between capillary number and inertia effects (Boom et al. 1995; Henderson et al. 1998, 2000a; Ali et al. 1997a, 1997b; Blom et al. 1997; Mott et al. 2000.). Well-deliverability forecasts for gas/condensate wells are usually performed with the help of numerical compositional simulators. Compositional simulation requires fine gridding to model the formation of the condensate bank with the required accuracy (Ali et al. 1997a). Non-Darcy flow and capillary-number effects (Mott 2003) are accounted for through empirical correlations, which require inputs such as the base capillary number (i.e., the minimum value required to see capillary-number effects), the reservoir absolute permeability, and the relative permeability curves. These are usually determined experimentally, but laboratory measurements at near-wellbore conditions are very difficult and expensive to obtain. An alternative, as shown in this paper, is to obtain them from well-test data. Well-test analysis is recognized as a valuable tool for reservoir surveillance and monitoring and provides estimates of a number of parameters required for reservoir characterization, reservoir simulation, and well-productivity forecasting. In gas/condensate reservoirs, when the BHP is below the dewpoint pressure, the effective permeability to gas in the near-wellbore region and at initial liquid saturation can be estimated with single-phase pseudopressures (Al-Hussainy et al. 1966) and a two- or three-region radial composite well-test-interpretation model (Chu and Shank 1993; Gringarten et al. 2000; Daungkaew et al. 2002), whereas the reservoir absolute permeability may be determined with two-phase steady-state pseudopressures (Raghavan et al. 1999; Xu and Lee 1999). In this paper, we show that well-test analysis can provide additional parameters, such as the gas relative permeabilities at both the endpoint and the near-wellbore saturations and the base capillary number. These in turn can be used to generate estimated relative permeability curves for gas.

An Equation To Predict Two-Phase Relative Permeability Curves in Fractures

2010 ◽  
Author(s):  
Andres Chima ◽  
Efren Antonio Chavez Iriarte ◽  
Zuly Himelda Calderon Carrillo
Keyword(s):  
Relative Permeability ◽  
Two Phase ◽  
Relative Permeability Curves

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

Materials ◽  
2020 ◽  
Vol 13 (4) ◽  
pp. 990
Author(s):  
Mingxing Bai ◽  
Lu Liu ◽  
Chengli Li ◽  
Kaoping Song
Keyword(s):  
Relative Permeability ◽  
Carbon Capture ◽  
Oil And Gas ◽  
Co2 Flooding ◽  
Two Phase ◽  
Permeability Characteristics ◽  
Gas Recovery ◽  
Miscible Flooding ◽  
Relative Permeability Curves ◽  
Carbon Dioxide Co2

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.

The Characteristics and Impacts Factors of Relative Permeability Curves in High Temperature and Low-Permeability Limestone Reservoirs

2014 ◽  
Vol 1010-1012 ◽  
pp. 1676-1683 ◽  
Author(s):  
Bin Li ◽  
Wan Fen Pu ◽  
Ke Xing Li ◽  
Hu Jia ◽  
Ke Yu Wang ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Water Saturation ◽  
Phase Region ◽  
Two Phase ◽  
Experimental Conditions ◽  
Irreducible Water Saturation ◽  
Productive Water ◽  
Relative Permeability Curves ◽  
Water Cut

To improve the understanding of the influence of effective permeability, reservoir temperature and oil-water viscosity on relative permeability and oil recovery factor, core displacement experiments had been performed under several experimental conditions. Core samples used in every test were natural cores that came from Halfaya oilfield while formation fluids were simulated oil and water prepared based on analyze data of actual oil and productive water. Results from the experiments indicated that the shape of relative permeability curves, irreducible water saturation, residual oil saturation, width of two-phase region and position of isotonic point were all affected by these factors. Besides, oil recovery and water cut were also related closely to permeability, temperature and viscosity ratio.

A Semianalytical Approach for Analysis of Wells Exhibiting Multiphase Transient Linear Flow: Application to Field Data

SPE Journal ◽  
2020 ◽  
Vol 25 (06) ◽  
pp. 3265-3279
Author(s):  
Hamidreza Hamdi ◽  
Hamid Behmanesh ◽  
Christopher R. Clarkson
Keyword(s):  
Numerical Model ◽  
Relative Permeability ◽  
History Matching ◽  
Volatile Oil ◽  
Low Permeability ◽  
Two Phase ◽  
Linear Flow ◽  
Field Case ◽  
Three Phase ◽  
Relative Permeability Curves

Summary Rate-transient analysis (RTA) is a useful reservoir/hydraulic fracture characterization method that can be applied to multifractured horizontal wells (MFHWs) producing from low-permeability (tight) and shale reservoirs. In this paper, we applied a recently developed three-phase RTA technique to the analysis of production data from an MFHW completed in a low-permeability volatile oil reservoir in the Western Canadian Sedimentary Basin. This RTA technique is used to analyze the transient linear flow regime for wells operated under constant flowing bottomhole pressure (BHP) conditions. With this method, the slope of the square-root-of-time plot applied to any of the producing phases can be used to directly calculate the linear flow parameter xfk without defining pseudovariables. The method requires a set of input pressure/volume/temperature (PVT) data and an estimate of two-phase relative permeability curves. For the field case studied herein, the PVT model is constructed by tuning an equation of state (EOS) from a set of PVT experiments, while the relative permeability curves are estimated from numerical model history-matchingresults. The subject well, an MFHW completed in 15 stages, produces oil, water, and gas at a nearly constant (measured downhole) flowing BHP. This well is completed in a low-permeability,near-critical volatile oil system. For this field case, application of the recently proposed RTA method leads to an estimate of xfk that is in close agreement (within 7%) with the results of a numerical model history match performed in parallel. The RTA method also provides pressure–saturation (P–S) relationships for all three phases that are within 2% of those derived from the numerical model. The derived P–S relationships are central to the use of other RTA methods that require calculation of multiphase pseudovariables. The three-phase RTA technique developed herein is a simple-yet-rigorous and accurate alternative to numerical model history matching for estimating xfk when fluid properties and relative permeability data are available.

A New Analytical Equation to Predict Gas-Water Two-Phase Relative Permeability Curves in Fractures

2014 ◽  
Author(s):  
Gang Lei ◽  
Pingchuan Dong ◽  
Shu Yang ◽  
Yuansheng Li ◽  
Shaoyuan Mo ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Analytical Equation ◽  
Two Phase ◽  
Relative Permeability Curves

A New Analytical Equation to Predict Gas-Water Two-Phase Relative Permeability Curves in Fractures

2014 ◽  
Author(s):  
Gang Lei ◽  
Pingchuan Dong ◽  
Shu Yang ◽  
Yuansheng Li ◽  
Shaoyuan Mo ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Analytical Equation ◽  
Two Phase ◽  
Relative Permeability Curves

scholarly journals New ν ‐type relative permeability curves for two‐phase flows through subsurface fractures

2015 ◽  
Vol 51 (4) ◽  
pp. 2807-2824 ◽  
Author(s):  
Noriaki Watanabe ◽  
Keisuke Sakurai ◽  
Takuya Ishibashi ◽  
Yutaka Ohsaki ◽  
Tetsuya Tamagawa ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Two Phase Flows ◽  
Two Phase ◽  
Subsurface Fractures ◽  
Relative Permeability Curves
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