An Improved Model For Estimating Three-Phase Oil-Water-Gas Relative Permeabilities From Two-Phase Oil-Water And Oil-Gas Data

1990 ◽  
Vol 29 (02) ◽  
Author(s):  
Sunil Kokal ◽  
Brij B. Maini
Keyword(s):  
Relative Permeabilities ◽  
Two Phase ◽  
Three Phase ◽  
Oil Water ◽  
Improved Model ◽  
Water Gas ◽  
Oil Gas

Determination of Two-Phase and Three-Phase Relative Permeabilities in Heavy Oil/Water/Gas Systems

2015 ◽  
Author(s):  
J. Modaresghazani ◽  
R. G. Moore ◽  
S. A. Mehta ◽  
K. C. Van Fraassen
Keyword(s):  
Heavy Oil ◽  
Relative Permeabilities ◽  
Two Phase ◽  
Three Phase ◽  
Oil Water ◽  
Water Gas

Removal of Water or Solids in Oil/Water, Gas/Solid and Gas/Liquid/Solid Pipelines Using Compact Inline Separator

2004 ◽  
Author(s):  
Parimal P. More ◽  
Cheolho Kang ◽  
William Paul Jepson
Keyword(s):  
Oil And Gas ◽  
Large Diameter ◽  
Cost Effective ◽  
Two Phase ◽  
Stage Separation ◽  
Three Phase ◽  
Scale Test ◽  
Oil Water ◽  
Water Pipeline ◽  
Water Gas

Traditionally separators that are used for separation purposes in oil and gas industries are often bulky in size and incur high operating costs. Latest research has led to the development of a novel and compact inline separator, which is even cost effective. This paper exhibits the efficiency of the inline separator determined for two-phase and three-phase separation in multiphase pipelines. Laboratory tests were carried out to remove sand and water using large diameter, industrial-scale test facilities. For the removal of water in oil/water pipeline, separation tests were carried out with liquid velocities ranging from 0.5 ∼ 2 m/s with 10, 50 and 90% water cuts. At first stage, effectiveness in excess of 90% was attained in each of the water cuts. In second stage separation, an effectiveness of 95% was achieved. For the removal of sand in sand/gas pipeline, gas velocities varying from 4 to 14 m/s were investigated. Here, the amount of sand collected after the separation was 99.9% of the total volume inserted into the system before separation. Separation tests for three phases, gas/liquid/sand were also carried out with string of superficial gas velocities of 4 to 10 m/s and superficial liquid velocities of 0.5 to 1.5 m/s. In this case, effectiveness of around 99% was obtained. Thus it can be concluded that the innovative, inline separation system can effectively remove sand and water and reduces or eliminates the risk of corrosion/erosion problems.

scholarly journals Can Effects of Temperature on Two-Phase Gas/Oil-Relative Permeabilities in Porous Media Be Ignored? A Critical Analysis

Energies ◽  
2020 ◽  
Vol 13 (13) ◽  
pp. 3444
Author(s):  
Saket Kumar ◽  
Sajjad Esmaeili ◽  
Hemanta Sarma ◽  
Brij Maini
Keyword(s):  
Critical Analysis ◽  
Thermal Recovery ◽  
Effect Of Temperature ◽  
Gas Oil ◽  
Relative Permeabilities ◽  
Two Phase ◽  
Recovery Processes ◽  
Fluid Properties ◽  
Oil Water ◽  
Oil Gas

Thermal recovery processes for heavy oil exploitation involve three-phase flow at elevated temperatures. The mathematical modeling of such processes necessitates the account of changes in the rock–fluid system’s flow behavior as the temperature rises. To this end, numerous studies on effects of the temperature on relative permeabilities have been reported in the literature. Compared to studies on the temperature effects on oil/water-relative permeabilities, studies (and hence, data) on gas/oil-relative permeabilities are limited. However, the role of temperature on both gas/oil and oil/water-relative permeabilities has been a topic of much discussion, contradiction and debate. The jury is still out, without a consensus, with several contradictory hypotheses, even for the limited number of studies on gas/oil-relative permeabilities. This study presents a critical analysis of studies on gas/oil-relative permeabilities as reported in the literature, and puts forward an undeniable argument that the temperature does indeed impact gas/oil-relative permeabilities and the other fluid–fluid properties contributing to flow in the reservoir, particularly in a thermal recovery process. It further concludes that such thermal effects on relative permeabilities must be accounted for, properly and adequately, in reservoir simulation studies using numerical models. The paper presents a review of most cited studies since the 1940s and identifies the possible primary causes that contribute to contradictory results among them, such as differences in experimental methodologies, experimental difficulties in flow data acquisition, impact of flow instabilities during flooding, and the differences in the specific impact of temperature on different rock–fluid systems. We first examined the experimental techniques used in measurements of oil/gas-relative permeabilities and identified the challenges involved in obtaining reliable results. Then, the effect of temperature on other rock–fluid properties that may affect the relative permeability was examined. Finally, we assessed the effect of temperature on parameters that characterized the two-phase oil/gas-relative permeability data, including the irreducible water saturation, residual oil saturation and critical gas saturation. Through this critical review of the existing literature on the effect of temperature on gas/oil-relative permeabilities, we conclude that it is an important area that suffers profoundly from a lack of a comprehensive understanding of the degree and extent of how the temperature affects relative permeabilities in thermal recovery processes, and therefore, it is an area that needs further focused research to address various contradictory hypotheses and to describe the flow in the reservoir more reliably.

Density Measurement of Three-Phase Flows Inside of Vertical Piping Using Planar Laser Induced Fluorescence PLIF

2021 ◽  
Author(s):  
Amy Brooke McCleney ◽  
Kevin Robert Supak
Keyword(s):  
High Speed ◽  
Gas Flow ◽  
Transient Flow ◽  
Two Phase ◽  
Mixture Density ◽  
Three Phase ◽  
Planar Laser ◽  
Flow Features ◽  
Oil Water ◽  
Oil Gas

Abstract Planar laser induced fluorescence (PLIF) is a measurement technique that can be used to provide a laboratory reference for validating the performance of field instrumentation that either directly measures mixture density or infers it from a combination of ancillary techniques. PLIF density measurements offer high-speed response and the ability to resolve minute flow features in transient flow patterns. Fundamentally, PLIF can also be used to verify multiphase flow models and predictive tools that are used for designing production piping. The use of PLIF to determine an instantaneous mixture density of two-phase flows has been successfully accomplished in previous fundamental laboratory studies found in literature. However, the use of this technique to determine the mixture density of three-phase flows for field-related scenarios has not been previously evaluated. To assess PLIF as a potential reference measurement system, a testing effort was undertaken to measure the instantaneous mixture density from a comingled oil-gas, water-oil, and oil-water-gas flow that was subjected to slug, churn, and bubble transient flow conditions inside of vertical piping. The objective of this work was to compare and validate the results obtained using the PLIF measurement approach against a commercially available gamma densitometer and tomography system for a variety of flowing conditions. The PLIF technique was able to resolve transient flow features and density values for both two-phase and three-phase flows through the piping. Distinct slug flow features such as the slug head, gas pocket, pocket collapse, and the tail were captured by PLIF and were observable in the raw image sequence captured by a high-speed camera. Additionally, the results for a variety of water-oil-gas flowing conditions were within 3% difference of a mixture density model that was calculated from liquid and gas flow measurements utilized in the test facility. The comparison of the PLIF results to the reference instrumentation indicates that this technique is successful at obtaining a mixture density for steady and transient oil, water, and gas comingled flows.

Application of Wavelet Analysis for Online Measurement of Crude Oils

2005 ◽  
Vol 295-296 ◽  
pp. 417-422
Author(s):  
X. Li ◽  
Z.L. Ding ◽  
F. Yuan
Keyword(s):  
Wavelet Analysis ◽  
Frequency Domain ◽  
Gas Flow ◽  
Lms Algorithm ◽  
Crude Oils ◽  
Online Measurement ◽  
Oil Pipeline ◽  
Three Phase ◽  
Oil Water ◽  
Water Gas

The correlation method had once been considered as one of the best methods for the measurement of multiphase flow. However, if the behavior of flow does not fit the ergodic random process, the measured cross correlation plot will have a gross distortion when the different components of flow do not pervade within one another to the full extent. We measured a variety of parameters of three phase oil/water/gas flow in an oil pipeline. The change of flow pattern is so complex that the measured signals are always contaminated by stochastic noises. The weak signals are very easily covered by the noise so that it will result in great deviation. Wavelet transformation is an analytical method of both time and frequency domain. The method can achieve signal decomposition and location in time and frequency domain through adjustment and translation of scale. An LMS algorithm in wavelet transform is studied for denoising the signals based on the use of a novel smart capacitive sensor to measure three phase oil/water/gas flow in oil pipeline. The results of simulation and data processing by MATLAB reveal that wavelet analysis has better denoising effects for online measurement of crude oils with high measurement precision and a wide application range.

An Improved Three-Phase Relative Permeability and Hysteresis Model for the Simulation of a Water-Alternating-Gas Injection

SPE Journal ◽  
2013 ◽  
Vol 18 (05) ◽  
pp. 841-850 ◽  
Author(s):  
H.. Shahverdi ◽  
M.. Sohrabi
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Gas Injection ◽  
Phase Flow ◽  
Relative Permeabilities ◽  
Water Alternating Gas ◽  
Three Phase ◽  
Three Phase Flow ◽  
Oil Water ◽  
Wag Injection

Summary Water-alternating-gas (WAG) injection in waterflooded reservoirs can increase oil recovery and extend the life of these reservoirs. Reliable reservoir simulations are needed to predict the performance of WAG injection before field implementation. This requires accurate sets of relative permeability (kr) and capillary pressure (Pc) functions for each fluid phase, in a three-phase-flow regime. The WAG process also involves another major complication, hysteresis, which is caused by flow reversal happening during WAG injection. Hysteresis is one of the most important phenomena manipulating the performance of WAG injection, and hence, it has to be carefully accounted for. In this study, we have benefited from the results of a series of coreflood experiments that we have been performing since 1997 as a part of the Characterization of Three-Phase Flow and WAG Injection JIP (joint industry project) at Heriot-Watt University. In particular, we focus on a WAG experiment carried out on a water-wet core to obtain three-phase relative permeability values for oil, water, and gas. The relative permeabilities exhibit significant and irreversible hysteresis for oil, water, and gas. The observed hysteresis, which is a result of the cyclic injection of water and gas during WAG injection, is not predicted by the existing hysteresis models. We present a new three-phase relative permeability model coupled with hysteresis effects for the modeling of the observed cycle-dependent relative permeabilities taking place during WAG injection. The approach has been successfully tested and verified with measured three-phase relative permeability values obtained from a WAG experiment. In line with our laboratory observations, the new model predicts the reduction of the gas relative permeability during consecutive water-and-gas-injection cycles as well as the increase in oil relative permeability happening in consecutive water-injection cycles.

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