An Inversion Method of Relative Permeability Curves in Polymer Flooding Considering Physical Properties of Polymer

SPE Journal ◽  
2018 ◽  
Vol 23 (05) ◽  
pp. 1929-1943 ◽  
Author(s):  
Yongge Liu ◽  
Jian Hou ◽  
Lingling Liu ◽  
Kang Zhou ◽  
Yanhui Zhang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Simulation Model ◽  
Relative Permeability ◽  
Polymer Flooding ◽  
Inversion Method ◽  
Residual Resistance ◽  
Relative Permeability Curve ◽  
Nonsteady State ◽  
State Method ◽  
Relative Permeability Curves

Summary Reliable relative permeability curves of polymer flooding are of great importance to the history matching, production prediction, and design of the injection and production plan. Currently, the relative permeability curves of polymer flooding are obtained mainly by the steady-state, nonsteady-state, and pore-network methods. However, the steady-state method is extremely time-consuming and sometimes produces huge errors, while the nonsteady-state method suffers from its excessive assumptions and is incapable of capturing the effects of diffusion and adsorption. As for the pore-network method, its scale is very small, which leads to great size differences with the real core sample or the field. In this paper, an inversion method of relative permeability curves in polymer flooding is proposed by combining the polymer-flooding numerical-simulation model and the Levenberg-Marquardt (LM) algorithm. Because the polymer-flooding numerical-simulation model by far offers the most-complete characterization of the flowing mechanisms of polymer, the proposed method is able to capture the effects of polymer viscosity, residual resistance, diffusion, and adsorption on the relative permeability. The inversion method was then validated and applied to calculate the relative permeability curve from the experimental data of polymer flooding. Finally, the effects of the influencing factors on the inversion error were analyzed, through which the inversion-error-prediction model of the relative permeability curve was built by means of multivariable nonlinear regression. The results show that the water relative permeability in polymer flooding is still far less than that in waterflooding, although the residual resistance of the polymer has been considered in the numerical-simulation model. Moreover, the accuracy of the polymer parameters has great effect on that of the inversed relative permeability curve, and errors do occur in the inversed water relative permeability curve—the measurements of the polymer solution viscosity, residual resistance factor, inaccessible pore-volume (PV) fraction, or maximum adsorption concentration have errors.

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.

Experimental studies on influence of temperature on relative permeability curves in sandstone reservoirs

2021 ◽  
pp. 014459872110408
Author(s):  
Zhiwei Zhai ◽  
Kunchao Li ◽  
Xing Bao ◽  
Jing Tong ◽  
Hongmei Yang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Relative Permeability ◽  
Experimental Studies ◽  
Influence Of Temperature ◽  
Relative Permeability Curve ◽  
Temperature Range ◽  
Irreducible Water Saturation ◽  
Influence Of Temperature On ◽  
Sandstone Reservoirs ◽  
Relative Permeability Curves

It is crucial to obtain the representative relative permeability curves for related numerical simulation and oilfield development. The influence of temperature on the relative permeability curve remains unclear. An unsteady method was adopted to investigate the influence of temperature (range from 25–130 °C) on the oil–water relative permeability curve of sandstone reservoirs in different blocks. Then, the experimental data was analyzed by using an improved Johnson–Bossler–Naumann method. Results reveal that with the increase in temperature within a certain temperature range: (1) the relative permeability of the oil and water phases increases; (2) the irreducible water saturation increases linearly, whereas the residual oil saturation decreases nonlinearly, and the oil recovery factor increases; and (3) the saturation of two equal permeability points moves to the right, and hydrophilicity becomes stronger. The findings will aid future numerical simulation studies, thus leading to the improvement of oil displacement efficiency.

scholarly journals History Matching and Production Prediction of Steam Drive Reservoir Based on Data-Space Inversion Method

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-11
Author(s):  
RuXiang Gong ◽  
JingSong Li ◽  
ZiJun Huang ◽  
Fei Wang ◽  
Hao Yang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Simulation Model ◽  
History Matching ◽  
Production Optimization ◽  
Production Performance ◽  
Inversion Method ◽  
Data Space ◽  
Steam Flooding ◽  
Space Inversion ◽  
Production Prediction

Recently, a data-space inversion (DSI) method has been proposed and successfully applied for the history matching and production optimization for conventional waterflooding reservoir. Under Bayesian framework, DSI can directly and effectively obtain posterior flow predictions without inverting any geological parameters of reservoir model. In this paper, we integrate the numerical simulation model with DSI method for rapid history matching and production prediction for steam flooding reservoir. Based on the finite volume method, a numerical simulation model is established and it is used to provide production data samples for DSI by the simulation of ensemble geological models. DSI-based production prediction model is then established and get trained by the historical data through the random maximum likelihood principle. The posterior production estimation can be obtained fast by training the DSI-based model with history data, but without any posterior geological parameters. The proposed method is applied for history matching and estimating production performance prediction in some numerical examples and a field case, and the results prove its effectiveness and reliability.

An Experimental Investigation of High and Low Salinity Waterflood Displacement Under the Steady-State Condition

2021 ◽  
Author(s):  
Abdulla Aljaberi ◽  
Seyed Amir Farzaneh ◽  
Shokoufeh Aghabozorgi ◽  
Mohammad Saeid Ataei ◽  
Mehran Sohrabi
Keyword(s):  
Steady State ◽  
Numerical Simulations ◽  
Relative Permeability ◽  
High Salinity ◽  
Unsteady State ◽  
Dispersion Effect ◽  
Low Salinity ◽  
Steady State Method ◽  
State Method ◽  
Relative Permeability Curves

Abstract Oil recovery by low salinity waterflood is significantly affected by fluid-fluid interaction through the micro-dispersion effect. This interaction influences rock wettability and relative permeability functions. Therefore, to gain a better insight into multiphase flow in porous media and perform numerical simulations, reliable relative permeability data is crucial. Unsteady-state or steady-state displacement methods are commonly used in the laboratory to measure water-oil relative permeability curves of a core sample. Experimentally, the unsteady-state core flood technique is more straightforward and less time-consuming compared to the steady-state method. However, the obtained data is limited to a small saturation range, and the associated uncertainty is not negligible. On the other hand, the steady-state method provides a more accurate dataset of two-phase relative permeability needed in the reservoir simulator for a reliable prediction of the high salinity and low salinity waterflood displacement performance. Considering the limitations of the unsteady state method, steady-state high salinity and low salinity brine experiments waterflood experiments were performed to compare the obtained relative permeability curves. The experiments were performed on a carbonate reservoir sample using a live reservoir crude oil under reservoir conditions. The test was designed so that the production and pressure drop curve covers a wider saturation range and provides enough data for analysis. Consequently, reliable relative permeability functions were obtained, initially, for a better comparison and prediction of the high salinity and the low salinity waterflood injections and then, to quantify the effect of low salinity waterflood under steady-state conditions. The results confirm the difference in relative permeability curves between high salinity and low salinity injections due to the micro-dispersion effect, which caused a decrease in water relative permeability and an increase in the oil relative permeability. These results also proved that low salinity brine can change the rock wettability from oil-wet or mixed-wet to more water-wet conditions. Furthermore, the obtained relative permeability curves extend across a substantial saturation range, making it valuable information required for numerical simulations. To the best of our knowledge, the reported data in this work is a pioneer in quantifying the impact of low salinity waterflood at steady-state conditions using a reservoir crude oil and reservoir rock, which is of utmost importance for the oil and gas industry.

The Effects of Interfacial Tension Dependent Relative Permeability on Sweep Efficiency and Oil Recovery Under Different Gas Injection Composition

2021 ◽  
Author(s):  
Mohd Ghazali Abd Karim ◽  
Wahyu Hidayat ◽  
Alzahrani Abdulelah
Keyword(s):  
Interfacial Tension ◽  
Simulation Model ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Gas Injection ◽  
Sweep Efficiency ◽  
Reservoir Properties ◽  
Relative Permeability Curve ◽  
Compositional Model ◽  
The Impact

Abstract The objective of this paper is to investigate the effects of interfacial tension dependent relative permeability (Kr_IFT) on oil displacement and recovery under different gas injection compositions utilizing a compositional simulation model. Oil production under miscible gas injection will result in variations of interfacial tension (IFT) due to changes in oil and gas compositions and other reservoir properties, such as pressure and temperature. Laboratory experiments show that changes in IFT will affect the two-phase relative permeability curve (Kr), especially for oil-gas system. Using a single relative permeability curve during the process from immiscible to miscible conditions will result in inaccurate gas mobility against water, which may lead to poor estimation of sweep efficiency and oil recovery. A synthetic sector compositional model was built to evaluate the effects of this phenomenon. Several simulation cases were investigated over different gas injection compositions (lean, rich and CO2), fluid properties and reservoir characterizations to demonstrate the impact of these parameters. Simulation model results show that the application of Kr_IFT on gas injection simulation modelling has captured different displacement behavior to provide better estimation of oil recovery and identify any upside potential.

Comparison of Calculated with Experimental Imbibition Relative Permeability

1971 ◽  
Vol 11 (04) ◽  
pp. 419-425 ◽  
Author(s):  
Carlon S. Land
Keyword(s):  
Relative Permeability ◽  
Reservoir Rock ◽  
Laboratory Measurements ◽  
Two Phase ◽  
Relative Permeability Curve ◽  
Gas Saturation ◽  
Phase Saturation ◽  
The Difference ◽  
Relative Permeability Curves ◽  
The Relationship

Abstract Two-phase imbibition relative permeability was measured in an attempt to validate a method of calculating imbibition relative permeability. The stationary-liquid-phase method was used to measure several hysteresis loops for alundum and Berea sandstone samples. The method of calculating imbibition relative permeability is described, and calculated relative permeability curves are compared with measured curves. The calculated relative Permeability is shown to be a reasonably good Permeability is shown to be a reasonably good approximation of measured values if an adjustment is made to some necessary data. Due to the compressibility of gas, which is used as the nonwetting phase, a correction to the measured trapped gas saturation is necessary to make it agree with the critical gas saturation of the imbibition relative permeability curve. Introduction The existence of hysteresis in the relationship of relative permeability to saturation has been recognized for many yews. Geden et al. and Osoba et al. called attention to the occurrence of hysteresis and the importance of the direction of saturation change on the relative permeability-saturation relations. It is generally believed that relative permeability is a function of saturation alone for a permeability is a function of saturation alone for a given direction of saturation change, but that there is a distinct difference in relative permeability curves for saturation changes in different directions. The reservoir engineer should be aware of this hysteresis, and he should select the relative permeability curve which is appropriate for the permeability curve which is appropriate for the recovery process of interest. The directions of saturation change have been designated "drainage" and "imbibition" in reference to changes in the wetting-phase saturation. In a two-phase system, an increase in the wetting-phase saturation is referred to as imbibition, while a decrease in wetting-phase saturation is called drainage. The solution-gas-drive recovery mechanism is controlled by relative permeability to oil and gas in which the saturation of oil, the wetting phase, is decreasing. In waterflooding a water-wet reservoir rock, the saturation of water, the wetting phase, is increasing. These two sets of relative permeability curves, gas-oil and oil-water, do not have the same relationship to the wetting-phase saturation. This difference is not due to the difference in fluid properties, but is a result of the difference in properties, but is a result of the difference in direction of saturation change. The flow properties of the drainage and imbibition systems differ because of the entrapment of the nonwetting phase during imbibition. As drainage occurs, the nonwetting phase occupies the most favorable flow channels. During imbibition, part of the nonwetting phase is bypassed by the increasing wetting phase, leaving a portion of the nonwetting phase in an immobile condition. This trapped part phase in an immobile condition. This trapped part of the nonwetting phase saturation does not contribute to the flow of that phase, and at a given saturation the relative permeability to the nonwetting phase is always less in the imbibition direction phase is always less in the imbibition direction than in the drainage direction. The concept that some of the nonwetting phase is mobile and some is immobile during a saturation change in the imbibition direction previously was used to develop equations for imbibition relative permeability. In this development, it was assumed permeability. In this development, it was assumed that the amount of entrapment at any saturation can be obtained from the relationship between initial nonwetting-phase saturations established in the drainage direction and residual saturations after complete imbibition. The equations for imbibition relative permeability were not verified by laboratory measurements. The purpose of this report is m give the results of a laboratory study of imbibition relative permeability and to present a comparison of calculated relative permeability with relative permeability from laboratory measurements. permeability from laboratory measurements. In two-phase systems, hysteresis is more prominent in the relative permeability to the nonwetting phase than in that to the wetting phase. The hysteresis in the wetting-phase relative permeability is believed to be very small, and thus difficult to distinguish tom normal experimental error. SPEJ P. 419

scholarly journals Effects of nanocomposite polymer flooding on Egyptian crude oil recovery

2020 ◽  
Vol 10 (8) ◽  
pp. 3937-3945
Author(s):  
M. E. Helmi ◽  
M. Abu El Ela ◽  
S. M. Desouky ◽  
M. H. Sayyouh
Keyword(s):  
Crude Oil ◽  
Relative Permeability ◽  
Polymer Matrix ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Western Desert ◽  
Polymerization Process ◽  
Reservoir Temperature ◽  
Nanocomposite Polymer ◽  
Relative Permeability Curves

Abstract In this work, a laboratory study of enhanced oil recovery (EOR) was carried out using Egyptian crude oil of 37°API extracted from a reservoir in the Western Desert to identify the optimum conditions for the application of locally prepared nanocomposite polymer flooding under harsh reservoir condition. In contrary to the other studies, we tested the ability of nanocomposite polymer where nanoparticles are involved in the polymer matrix during polymerization process. Measurements of viscosity and shear rate of several solutions were taken. Displacement runs were conducted at different conditions of nanocomposite polymer salinities (10,000, 20,000, 30,000, 40,000, 50,000, 60,000 and 65,000 ppm), concentrations (1, 1.5, 2, 2.5, 3, 3.5 and 4 g/L) and slug sizes (0.2, 0.4, 0.6 and 0.8 PV). A linear sandpack (length of 62.5 cm and diameter of 2″) was prepared and wrapped with thermal jacket to simulate several reservoir temperatures. It was filled by selected sand size to produce linear sandpack model with reasonable porosity (22%) and permeability (129–157 mD) values. The model was used to perform several displacements runs for waterflooding and nanocomposite polymer flooding. The results of the flood runs are analyzed using the water–oil relative permeability curves. The measurements of the solutions properties showed that the critical concentration of the used nanocomposite polymer in the solution is 2 g/L. Also, it was observed that the used nanocomposite polymer solution could withstand a salinity of 60,000 ppm. As a result of the flooding, it was found that the optimum economical slug size of the used nanocomposite polymer is 0.4 PV at reservoir temperature of 40 °C. The results indicated also that the used nanocomposite polymer could withstand a reservoir temperature of 90 °C. The water–oil relative permeability curves showed an enhancement of oil relative permeability and a decrease in the water relative permeability using nanocomposite polymer over waterflooding. The cost of the used nanocomposite polymer with a concentration of 2 g/L and slug size of 0.4 PV is 0.626 $ for each barrel of the incremental oil recovery. Based on the results of this work, it is clear that involving nanoparticles such as silica in the polymer matrix composition improves its properties, thermal and salinity resistivity. Such study is an original contribution to carry out successful nanocomposite polymer EOR projects.

Numerical Investigation of the Effects of Core Heterogeneities on Waterflood Relative Permeabilities

1970 ◽  
Vol 10 (04) ◽  
pp. 381-392 ◽  
Author(s):  
John D. Huppler
Keyword(s):  
Numerical Simulation ◽  
Porous Medium ◽  
Pressure Drop ◽  
Difference Equation ◽  
Relative Permeability ◽  
Phase Difference ◽  
Two Dimensional ◽  
Relative Permeabilities ◽  
Two Phase ◽  
Relative Permeability Curves

Abstract Numerical simulation techniques were used to investigate the effects of common core heterogeneities upon apparent waterflood relative-permeability results. Effects of parallel and series stratification, distributed high and low permeability lenses, and vugs were considered. permeability lenses, and vugs were considered. Well distributed heterogeneities have little effect on waterflood results, but as the heterogeneities become channel-like, their influence on flooding behavior becomes pronounced. Waterflooding tests at different injection rates are suggested as the best means of assessing whether heterogeneities are important. Techniques for testing stratified or lensed cores are recommended. Introduction Since best results from waterflood tests performed on core plugs are obtained with homogeneous cores, plugs selected for testing are chosen for their plugs selected for testing are chosen for their apparent uniformity. We know, however, that uniform appearance can be misleading. For example, flushing concentrated hydrochloric acid through an apparently homogeneous core plug often produces "wormholes" in higher permeability regions. Also, we sometimes find that all core plugs from a region of interest have obvious heterogeneities, so any flooding tests must be run on nonhomogeneous core plugs. plugs. Nevertheless, relative permeabilities, as obtained routinely from core waterflood data, are calculated using the assumption that the core is a homogeneous porous medium. While it is obvious that porous medium. While it is obvious that heterogeneties mill affect these apparent relative permeabilities, there appear to be no experimental permeabilities, there appear to be no experimental results reported in the literature to indicate just how serious the problem is. Accordingly, a computer simulation study of core waterfloods was conducted to systematically examine the effects of different sizes and types of core heterogeneities on flood results. The study was performed by numerical simulation using two-dimensional, two-phase difference equation approximations to describe the immiscible water-oil displacement. For each simulation the permeability and porosity distribution of the heterogeneous core to be studied was specified; fluid flow characteristics of the system, including a single set of input relative-permeabilities curves, were stipulated The system was set in capillary pressure equilibrium at the reducible water saturation. Then a waterflood simulation was performed. From the resulting fluid production and pressure-drop data a set of production and pressure-drop data a set of relative-permeability curves was calculated using the standard computational procedure applicable to homogeneous cores. In this paper these calculated relative-permeability curves are denoted as "waterflood" curves to distinguish them from the specified input curves. The waterflood relative-permeability curves should closely match the input curves for homogeneous systems. Since the same set of input relative-permeability curves was used for all rock sections, deviations of the waterflood from the input relative-permeability curves gave an indication of the effects of heterogeneities. When the system was heterogeneous and there was good agreement between waterflood and input relative-permeability curves, then the heterogeneities did not strongly influence the flow behavior and the system responded homogeneously. MATHEMATICAL MODEL AND METHOD The waterflood simulations were carried out using two-dimensional, two-phase difference equation approximations to the incompressible-flow differential equations:* .....................(1) ....................(2) SPEJ P. 381

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