Simulation of Immiscible WAG Experiments Performed in Carbonate Rocks: The Impact of Heterogeneity on Hysteresis Phenomenon

2021 ◽  
Author(s):  
Latifa Obaid Alnuaimi ◽  
Mehran Sohrabi ◽  
Shokoufeh Aghabozorgi ◽  
Ahmed Alshmakhy
Keyword(s):  
Relative Permeability ◽  
Carbonate Rocks ◽  
Carbonate Rock ◽  
Hysteresis Effect ◽  
Hysteresis Phenomenon ◽  
Hysteresis Model ◽  
Sandstone Rock ◽  
Three Phase ◽  
The Impact ◽  
Permeability Data

Abstract Simulation of Water-Alternating-Gas (WAG) Experiments require precise estimation of hysteresis phenomenon in three-phase relative permeability. Most of the research available in the literature are focused on experiments performed on sandstone rocks and the study of carbonate rocks has attracted less attention. In this paper, a recently published hysteresis model by Heriot-Watt University (HWU) was used for simulation of WAG experiments conducted on mixed-wet homogenous carbonate rock. In this study, we simulated immiscible WAG experiments, which were performed under reservoir conditions on mixed-wet carbonate reservoir rock extracted from Abu Dhabi field by using real reservoir fluids. Experiments are performed with different injection scenarios and at high IFT conditions. Then, the results of the coreflood experiments were history matched using 3RPSim to generate two-phase and three-phase relative permeability data. Finally, the hysteresis model suggested by Heriot-Watt University was used for the estimation of hysteresis in relative permeability data. The performance of the model was compared with the experimental data from sandstones to evaluate the impact of heterogeneity on hysteresis phenomenon. It was shown that the available correlations for estimation of three-phase oil relative permeability fail to simulate the oil production during WAG experiments, while the modified Stone model suggested by HWU provided a better prediction. Overall, HWU hysteresis model improved the match for trapped gas saturation and pressure drop. The results show that the hysteresis effect is less dominant in the carbonate rock compared to the sandstone rock. The tracer test results show that the carbonate rock is more homogenous compared to sandstone rock. Therefore, the conclusion is that the hysteresis effect is negligible in homogenous systems.

Experimental Study and History-Match of Near-Miscible WAG Coreflood Experiments on Mixed-Wet Carbonate Rocks

2021 ◽  
Author(s):  
Mohamed Mehdi El Faidouzi
Keyword(s):  
Relative Permeability ◽  
Carbonate Rocks ◽  
Hysteresis Model ◽  
Relative Permeabilities ◽  
Two Phase ◽  
Recovery Method ◽  
Phase Displacement ◽  
Three Phase ◽  
Displacement Experiments ◽  
Phase Water

Abstract Water-alternating-gas (WAG) injection, both miscible and immiscible, is a widely used enhanced oil recovery method with over 80 field cases. Despite its prevalence, the numerical modeling of the physical processes involved remains poorly understood, and existing models often lack predictability. Part of the complexity stems from the component exchange between gas and oil and the hysteretic relative permeability effects. Thus, improving the reliability of numerical models requires the calibration of the equation of state (EOS) against phase behavior data from swelling/extraction and slim-tube tests, and the calibration of the three-phase relative permeability model against WAG coreflood experiments. This paper presents the results and interpretation of a complete set of two-phase and thee-phase displacement experiments on mixed-wet carbonate rocks. The three-phase WAG experiments were conducted on the same composite core at near-miscible reservoir condition; experiments differ in the injection order and length of their injection cycles. First, the two-phase water/oil and gas/oil displacement experiments and first cycles of WAG were used to estimate the two-phase relative permeabilities. Then, a synchronized history-matching procedure over the full set of WAG experiments and cycles was carried out to tune Larsen ans Skauge WAG hysteresis model—namely the Land gas traping parameter, the gas reduction exponent, the residual oil reduction factor and three-phase water relative permeability. The second part of this paper deals with the multiphase upscaling of microscopic displacement properties from plug to coarse grid reservoir scale. The two-phase relative permeability curves and three-phase WAG parameters were upscaled using a sector model to preserve the displacement process and reservoir performance. The result of the coreflood calibration indicate that the two-phase displacement and first cycles of WAG yield a consistent set of two-phase relative permeabilities. Including the full set of WAG experiments allowed a robust calibration of the hysteresis model.

Relative Permeability Characterization for Water-Alternating-Gas Injection in Oil Reservoirs

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 0799-0808 ◽  
Author(s):  
H.. Shahverdi ◽  
M.. Sohrabi
Keyword(s):  
Relative Permeability ◽  
Gas Injection ◽  
Hysteresis Effect ◽  
Oil Reservoirs ◽  
Unsteady State ◽  
Two Phase ◽  
Water Alternating Gas ◽  
Three Phase ◽  
Phase Water ◽  
Wag Injection

Summary Large quantities of oil usually remain in oil reservoirs after conventional waterfloods. A significant part of this remaining oil can still be economically recovered by water-alternating-gas (WAG) injection. WAG injection involves drainage and imbibition processes taking place sequentially; therefore, the numerical simulation of the WAG process requires reliable knowledge of three-phase relative permeability (kr) accounting for cyclic-hysteresis effects. In this study, the results of a series of unsteady-state two-phase displacements and WAG coreflood experiments were used to investigate the behavior of three-phase kr and hysteresis effects in the WAG process. The experiments were performed on two different cores with different characteristics and wettability conditions. An in-house coreflood simulator was developed to obtain three-phase relative permeability values directly from unsteady-state WAG experiments by history matching the measured recovery and differential-pressure profiles. The results show that three-phase gas relative permeability is reduced in consecutive gas-injection cycles and consequently the gas mobility and injectivity drop significantly with successive gas injections during the WAG process, under different rock conditions. The trend of hysteresis in the relative permeabilty of gas (krg) partly contradicts the existing hysteresis models available in the literature. The three-phase water relative permeability (krw) of the water-wet (WW) core does not exhibit considerable hysteresis effect during different water injections, whereas the mixed-wet (MW) core shows slight cyclic hysteresis. This may indicate a slight increase of the water injectivity in the subsequent water injections in the WAG process under MW conditions. Insignificant hysteresis is observed in the oil relative permeability (kro) during different gas-injection cycles for both WW and MW rocks. However, a considerable cyclic-hysteresis effect in kro is observed during water-injection cycles of WAG, which is attributed to the reduction of the residual oil saturation (ROS) during successive water injections. The kro of the WW core exhibits much-more cyclic-hysteresis effect than that of the MW core. No models currently exist in reservoir simulators that can capture the observed cyclic-hysteresis effect in oil relative permeability for the WAG process. Investigation of relative permeability data obtained from these displacement tests at different rock conditions revealed that there is a significant discrepancy between two-phase and three-phase relative permeability of all fluids. This highlights that not only the three-phase relative permeability of the intermediate phase (oil), but also the three-phase kr of the wetting phase (water) and nonwetting phase (gas) are functions of two independent saturations.

Three-Phase Relative Permeability Measurements by Unsteady-State Method

1966 ◽  
Vol 6 (03) ◽  
pp. 199-205 ◽  
Author(s):  
A.M. Sarem
Keyword(s):  
Relative Permeability ◽  
Two Phase Flow ◽  
Phase Flow ◽  
Unsteady State ◽  
Two Phase ◽  
Three Phase ◽  
Three Phase Flow ◽  
State Method ◽  
Permeability Data ◽  
Saturation History

Abstract For the performance prediction of multiphase oil recovery processes such as steam stimulation, there is an acute need for three-phase relative permeability data. No fast and simple experimental technique, such as the unsteady-state method proposed by Welge for two-phase flow, is available for the three-phase flow. In this paper, an unsteady-state method is presented for obtaining three-phase relative permeability data; this method is as fast and easy as Welge's method for two-phase flow. Analytical expressions are derived by extension of the Buckley-Leverett theory to three-phase flow to express the saturation at the outflow face for all three phases in terms of the known parameters. It is assumed that the fractional flow and relative permeability of each phase are a function of the saturation of that phase. Other simplifying assumptions made include the neglect of capillary and gravity effects. The effect of saturation history upon relative permeability is acknowledged and attainment of similar saturation history in laboratory and field is recommended. The required experimental work and computations are simple to perform. The test core is presaturated with oil and water, then subjected to gas drive. During the test, required data are the rates of oil, water, and gas production, together with pressure drop and temperature. The ordinary gas-oil unsteady-state relative permeability apparatus can be readily modified to measure the required data. The proposed technique was applied to samples of a Berea and a reservoir core. The effect of saturation history upon relative permeability was studied on one Berea core. It was found that increase in initial water saturation has a similar effect upon three-phase relative permeability as it does in two-phase flow. Introduction In the light of increasing demand for three-phase, relative permeability data for predicting the performance of thermal and other multiphase-flow recovery processes, a simple and accurate method of experimental determination of such data is extremely desirable. Leverett and Lewis1 described the simultaneous flow method of obtaining three-phase relative permeability data. However, Caudle et al.2 reported that this method is very time consuming and cumbersome. Corey3 proposed calculating the three-phase relative permeability from measured krg data. Corey's theory is based on simplified capillary pressure curves,4 assuming a straight line relationship between 1/Pc2 and saturation. Also, Corey's method assumes a preferentially water-wet system. The simplest and quickest method of obtaining three-phase relative permeability data is the unsteady-state method where, for instance, oil and water are displaced by gas. However, in such a test the correlation of average saturation with relative permeability does not give a valid relationship because the rates of oil, water and gas flow in the sample change continuously from the upstream to downstream end. This difficulty in calculating valid relationships was solved by Welge for two-phase flow by deriving an expression from Buckley and Leverett frontal advance equations.5,6 In this paper, relations are established to determine the outflow face saturation and relative permeability to all phases in a three-phase flow displacement experiment. Proposed Method The fundamentals established by Buckley and Leverett5 for two-phase flow were extended to three-phase flow and used as a basis for the derivation of saturation equations. This approach is comparable to Welge's6 use of Buckley and Leverett theory in arriving at expressions to determine the outflow face saturation of the displacing fluid in a two-phase flow system.

Novel Three-Phase Compositional Relative Permeability and Three-Phase Hysteresis Models

SPE Journal ◽  
2014 ◽  
Vol 20 (01) ◽  
pp. 21-34 ◽  
Author(s):  
Mohammad R. Beygi ◽  
Mojdeh Delshad ◽  
Venkateswaran S. Pudugramam ◽  
Gary A. Pope ◽  
Mary F. Wheeler
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Co2 Storage ◽  
Carbonate Reservoir ◽  
Mobility Control ◽  
Hysteresis Model ◽  
Permeability Model ◽  
Three Phase ◽  
Trapping Model ◽  
Wet Rocks

Summary Mobility-control methods have the potential to improve coupled enhanced oil recovery (EOR) and carbon dioxide (CO2) storage technique (CO2-EOR). There is a need for improved three-phase relative permeability models with hysteresis, especially including the effects of cycle dependency so that more-accurate predictions of these methods can be made. We propose new three-phase relative permeability and three-phase hysteresis models applicable to different fluid configurations in a porous medium under different wettability conditions. The relative permeability model includes both the saturation history and compositional effects. Three-phase parameters are estimated on the basis of saturation-weighted interpolation of two-phase parameters. The hysteresis model is an extension of the Land trapping model (Land 1968) but with a dynamic Land coefficient introduced. The trapping model estimates a constantly increasing trapped saturation for intermediate-wetting and nonwetting phases. The hysteresis model overcomes some of the limitations of existing three-phase hysteresis models for nonwater-wet rocks and mitigates the complexity associated with commonly applied models in numerical simulators. The relative permeability model is validated by use of multicyclic three-phase water-alternating-gas experimental data for nonwater-wet rocks. Numerical simulations of a carbonate reservoir with and without hysteresis were used to assess the effect of the saturation direction and saturation path on gas entrapment and oil recovery.

Three-phase relative permeability and hysteresis effect during WAG process in mixed wet and low IFT systems

2011 ◽  
Vol 78 (3-4) ◽  
pp. 732-739 ◽  
Author(s):  
Hamidreza Shahverdi ◽  
Mehran Sohrabi ◽  
Mobeen Fatemi ◽  
Mahmoud Jamiolahmady
Keyword(s):  
Relative Permeability ◽  
Hysteresis Effect ◽  
Three Phase

Experimental Investigation of Near-Miscible Water-Alternating-Gas Injection Performance in Water-Wet and Mixed-Wet Systems

SPE Journal ◽  
2013 ◽  
Vol 18 (01) ◽  
pp. 114-123 ◽  
Author(s):  
S. Mobeen Fatemi ◽  
Mehran Sohrabi
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Laboratory Data ◽  
Co2 Injection ◽  
Water Alternating Gas ◽  
Three Phase ◽  
The Impact ◽  
Wag Injection

Summary Laboratory data on water-alternating-gas (WAG) injection for non-water-wet systems are very limited, especially for near-miscible (very low IFT) gas/oil systems, which represent injection scenarios involving high-pressure hydrocarbon gas or CO2 injection. Simulation of these processes requires three-phase relative permeability (kr) data. Most of the existing three-phase relative permeability correlations have been developed for water-wet conditions. However, a majority of oil reservoirs are believed to be mixed-wet and, hence, prediction of the performance of WAG injection in these reservoirs is associated with significant uncertainties. Reliable simulation of WAG injection, therefore, requires improved relative permeability and hysteresis models validated by reliable measured data. In this paper, we report the results of a comprehensive series of coreflood experiments carried out in a core under natural water-wet conditions. These included water injection, gas injection, and also WAG injection. Then, to investigate the impact of wettability on the performance of these injection strategies, the wettability of the same core was changed to mixed-wet (by aging the core in an appropriate crude oil) and a similar set of experiments were performed in the mixed-wet core. WAG experiments under both wettability conditions started with water injection (I) followed by gas injection (D), and this cyclic injection of water and gas was repeated (IDIDID). The results show that in both the water-wet and mixed-wet cores, WAG injection performs better than water injection or gas injection alone. Changing the rock wettability from water-wet to mixed-wet significantly improves the performance of water injection. Under both wettability conditions (water-wet and mixed-wet), the breakthrough (BT) of the gas during gas injection happens sooner than the BT of water in water injection. Ultimate oil recovery by gas injection is considerably higher than that obtained by water injection in the water-wet system, while in the mixed-wet system, gas injection recovers considerably less oil.

scholarly journals The Impact of Mineral Dissolution on Drainage Relative Permeability and Residual Trapping in Two Carbonate Rocks

2019 ◽  
Vol 131 (2) ◽  
pp. 363-380 ◽  
Author(s):  
Ben Niu ◽  
Samuel Krevor
Keyword(s):  
Multiphase Flow ◽  
Pore Structure ◽  
Relative Permeability ◽  
Pore Volume ◽  
Carbonate Rocks ◽  
Mineral Dissolution ◽  
Carbonate Dissolution ◽  
Flow Properties ◽  
Residual Trapping ◽  
The Impact

AbstractCarbon dioxide injection into deep saline aquifers is governed by a number of physico-chemical processes including mineral dissolution and precipitation, multiphase fluid flow, and capillary trapping. These processes can be coupled; however, the impact of fluid–rock reaction on the multiphase flow properties is difficult to study and is not simply correlated with variations in porosity. We observed the impact of rock mineral dissolution on multiphase flow properties in two carbonate rocks with distinct pore structures. Observations of steady-state $$\hbox {N}_2$$N2–water relative permeability and residual trapping were obtained, along with mercury injection capillary pressure characteristics. These tests alternated with eight stages in which 0.5% of the mineral volume was uniformly dissolved into solution from the rock cores using an aqueous solution with a temperature-controlled acid. Variations in the multiphase flow properties did not relate simply to changes in porosity, but corresponded to the changes in the underlying pore structure. In the Ketton carbonate, dissolution resulted in an increase in the fraction of pore volume made up by the smallest pores and a decrease in the fraction made up by the largest pores. This resulted in an increase in the relative permeability to the nonwetting phase, a decrease in the relative permeability to the wetting phase, and a modest, but systematic decrease in residual trapping. In the Estaillades carbonate, dissolution resulted in an increase in the fraction of pore volume made up by pores in the central range of the initial pore size distribution, and a corresponding decrease in the fraction made up by both the smallest and largest pores. This resulted in a decrease in the relative permeability to both the wetting and nonwetting fluid phases and no discernible impact on the residual trapping. In summary, the impact of rock matrix dissolution will be strongly dependent on the impact of that dissolution on the underlying pore structure of the rock. However, if the variation in pore structure can be observed or estimated with modelling, then it should be possible to estimate the impacts on multiphase flow properties.

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