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.

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.

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.

scholarly journals Experimental Studies of Immiscible High-Nitrogen Natural Gas WAG Injection Efficiency in Mixed-Wet Carbonate Reservoir

Energies ◽  
2020 ◽  
Vol 13 (9) ◽  
pp. 2346
Author(s):  
Mirosław Wojnicki ◽  
Jan Lubaś ◽  
Marcin Warnecki ◽  
Jerzy Kuśnierczyk ◽  
Sławomir Szuflita
Keyword(s):  
Natural Gas ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Experimental Studies ◽  
Carbonate Reservoir ◽  
High Nitrogen ◽  
The Impact ◽  
Wag Injection

Crucial oil reservoirs are located in naturally fractured carbonate formations and are currently reaching a mature phase of production. Hence, a cost-effective enhanced oil recovery (EOR) method is needed to achieve a satisfactory recovery factor. The paper focuses on an experimental investigation of the efficiency of water alternating sour and high-nitrogen (~85% N2) natural gas injection (WAG) in mixed-wetted carbonates that are crucial reservoir rocks for Polish oil fields. The foam-assisted water alternating gas method (FAWAG) was also tested. Both were compared with continuous water injection (CWI) and continuous gas injection (CGI). A series of coreflooding experiments were conducted within reservoir conditions (T = 126 ℃, P = 270 bar) on composite cores, and each consisted of four reservoir dolomite core plugs and was saturated with the original reservoir fluids. In turn, some of the experiments were conducted on artificially fractured cores to evaluate the impact of fractures on recovery efficiency. The performance evaluation of the tested methods was carried out by comparing oil recoveries from non-fractured composite cores, as well as fractured. In the case of non-fractured cores, the WAG injection outperformed continuous gas injection (CGI) and continuous water injection (CWI). As expected, the presence of fractures significantly reduced performance of WAG, CGI and CWI injection modes. In contrast, with regard to FAWAG, deployment of foam flow in the presence of fractures remarkably enhanced oil recovery, which confirms the possibility of using the FAWAG method in situations of premature gas breakthrough. The positive results encourage us to continue the research of the potential uses of this high-nitrogen natural gas in EOR, especially in the view of the utilization of gas reservoirs with advantageous location, high reserves and reservoir energy.

scholarly journals Investigation of Oil Recovery in Fractured Carbonate Rock by

2016 ◽  
Vol 6 (1) ◽  
pp. 14
Author(s):  
H. Karimaie ◽  
O. Torsæter
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Co2 Injection ◽  
Recovery Method ◽  
Asmari Limestone ◽  
Fractured Carbonate ◽  
Efficient Recovery ◽  
Live Oil ◽  
Non Equilibrium

The purpose of the three experiments described in this paper is to investigate the efficiency of secondary andtertiary gas injection in fractured carbonate reservoirs, focusing on the effect of equilibrium gas,re-pressurization and non-equilibrium gas. A weakly water-wet sample from Asmari limestone which is the mainoil producing formation in Iran, was placed vertically in a specially designed core holder surrounded withfracture. The unique feature of the apparatus used in the experiment, is the capability of initializing the samplewith live oil to obtain a homogeneous saturation and create the fracture around it by using a special alloy whichis easily meltable. After initializing the sample, the alloy can be drained from the bottom of the modified coreholder and create the fracture which is filled with live oil and surrounded the sample. Pressure and temperaturewere selected in the experiments to give proper interfacial tensions which have been measured experimentally.Series of secondary and tertiary gas injection were carried out using equilibrium and non-equilibrium gas.Experiments have been performed at different pressures and effect of reduction of interfacial tension werechecked by re-pressurization process. The experiments showed little oil recovery due to water injection whilesignificant amount of oil has been produced due to equilibrium gas injection and re-pressurization. Results alsoreveal that CO2 injection is a very efficient recovery method while injection of C1 can also improve the oilrecovery.

scholarly journals MODEL-BASED OPTIMIZATION OF CYCLES OF CO2 WATER-ALTERNATING-GAS (CO2-WAG) INJECTION IN CARBONATE RESERVOIR

2022 ◽  
Vol 15 (4) ◽  
pp. 139-149
Author(s):  
F. G. A. Pereira ◽  
V. E. Botechia ◽  
D. J. Schiozer
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Co2 Production ◽  
Co2 Injection ◽  
Optimal Size ◽  
Control Variables ◽  
Limit Values ◽  
Water Alternating Gas ◽  
Production Wells ◽  
The Impact

Pre-salt reservoirs are among the most important discoveries in recent decades due to the large quantities of oil in them. However, high levels of uncertainties related to its large gas/CO2 production prompt a more complex gas/CO2 management, including the use of alternating water and gas/CO2 injection (WAG) as a recovery mechanism to increase oil recovery from the field. The purpose of this work is to develop a methodology to manage cycle sizes of the WAG/CO2, and analyze the impact of other variables related to the management of producing wells during the process. The methodology was applied to a benchmark synthetic reservoir model with pre-salt characteristics. We used five approaches to evaluate the optimum cycle size under study, also assessing the impact of the management of producing wells: (A) without closing producers due to gas-oil ratio (GOR) limit; (B) GOR limit fixed at a fixed value (1600 m³/m³) for all wells; (C) GOR limit optimized per well; (D) joint optimization between GOR limit values of producers and WAG cycles; and (E) optimization of the cycle size per injector well with an optimized GOR limit. The results showed that the optimum cycle size depends on the management of the producers. Leaving all production wells open until the end of the field's life (without closing based on the GOR limit) or controlling the wells in a more restricted manner (with closing based on the GOR limit), led to significant variation of the results (optimal size of the WAG/CO2 cycles). Our study, therefore, demonstrates that the optimum cycle size depends on other control variables and can change significantly due to these variables. This work presents a study that aimed to manage the WAG-CO2 injection cycle size by optimizing the life cycle control variables to obtain better economic performance within the premises already established, such as the total reinjection of gas/CO2 produced, also analyzing the impact of other variables (management of producing wells) along with the WAG-CO2 cycles.

scholarly journals Performance Quantification of Enhanced Oil Recovery Methods in Fractured Reservoirs

Energies ◽  
2021 ◽  
Vol 14 (16) ◽  
pp. 4739
Author(s):  
Riyaz Kharrat ◽  
Mehdi Zallaghi ◽  
Holger Ott
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Driving Forces ◽  
Fractured Reservoirs ◽  
Gas Injection ◽  
Capillary Forces ◽  
Dimensionless Numbers ◽  
Water Alternating Gas ◽  
Eor Processes ◽  
Wag Injection

The enhanced oil recovery mechanisms in fractured reservoirs are complex and not fully understood. It is technically challenging to quantify the related driving forces and their interaction in the matrix and fractures medium. Gravity and capillary forces play a leading role in the recovery process of fractured reservoirs. This study aims to quantify the performance of EOR methods in fractured reservoirs using dimensionless numbers. A systematic approach consisting of the design of experiments, simulations, and proxy-based optimization was used in this work. The effect of driving forces on oil recovery for water injection and several EOR processes such as gas injection, foam injection, water-alternating gas (WAG) injection, and foam-assisted water-alternating gas (FAWAG) injection was analyzed using dimensionless numbers and a surface response model. The results show that equilibrium between gravitational and viscous forces in fracture and capillary and gravity forces in matrix blocks determines oil recovery performance during EOR in fractured reservoirs. When capillary forces are dominant in gas injection, fluid exchange between fracture and matrix is low; consequently, the oil recovery is low. In foam-assisted water-alternating gas injection, gravity and capillary forces are in equilibrium conditions as several mechanisms are involved. The capillary forces dominate the water cycle, while gravitational forces govern the gas cycle due to the foam enhancement properties, which results in the highest oil recovery factor. Based on the performed sensitivity analysis of matrix–fracture interaction on the performance of the EOR processes, the foam and FAWAG injection methods were found to be more sensitive to permeability contrast, density, and matrix block highs than WAG injection.

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.

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