Numerical Optimization of WAG Injection in a Sandstone Field using a Coupled Surface and Subsurface Model

2021 ◽  
Author(s):  
Thaer I. Ismail ◽  
Emad W. Al-Shalabi ◽  
Mahmoud Bedewi ◽  
Waleed AlAmeri
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Coupled Model ◽  
Sensitivity Study ◽  
Mobility Control ◽  
Base Case ◽  
The North ◽  
Injection Process ◽  
Interaction Terms ◽  
Wag Injection

Abstract Gas injection is one of the most commonly used enhanced oil recovery (EOR) methods. However, there are multiple problems associated with gas injection including gravity override, viscous fingering, and channeling. These problems are due to an adverse mobility ratio and cause early breakthrough of the gas resulting, in poor recovery efficiency. A Water Alternating Gas (WAG) injection process is recommended to resolve these problems through better mobility control of gas, leading to better project economics. However, poor WAG design and lack of understanding of the different factors that control its performance might result in unfavorable oil recovery. Therefore, this study provides more insight into improving WAG oil recovery by optimizing different surface and subsurface WAG parameters using a coupled surface and subsurface simulator. Moreover, the work investigates the effects of hysteresis on WAG performance. This case study investigates a field named Volve, which is a decommissioned sandstone field in the North Sea. Experimental design of factors influencing WAG performance on this base case was studied. Sensitivity analysis was performed on different surface and subsurface WAG parameters including WAG ratio, time to start WAG, total gas slug size, cycle slug size, and tubing diameter. A full two-level factorial design was used for the sensitivity study. The significant parameters of interest were further optimized numerically to maximize oil recovery. The results showed that the total slug size is the most important parameter, followed by time to start WAG, and then cycle slug size. WAG ratio appeared in some of the interaction terms while tubing diameter effect was found to be negligible. The study also showed that phase hysteresis has little to no effect on oil recovery. Based on the optimization, it is recommended to perform waterflooding followed by tertiary WAG injection for maximizing oil recovery from the Volve field. Furthermore, miscible WAG injection resulted in an incremental oil recovery between 5 to 11% OOIP compared to conventional waterflooding. WAG optimization is case-dependent and hence, the findings of this study hold only for the studied case, but the workflow should be applicable to any reservoir. Unlike most previous work, this study investigates WAG optimization considering both surface and subsurface parameters using a coupled model.

scholarly journals Literature Review of Water Alternation Gas Injection

2018 ◽  
Vol 7 (2) ◽  
pp. 33-45 ◽  
Author(s):  
Mohammed Alsharif Samba ◽  
Mahmoud Omran Elsharafi
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Mobility Control ◽  
Literature Study ◽  
Sweep Efficiency ◽  
Water Alternating Gas ◽  
Basic Concepts ◽  
Number Of Cycles ◽  
Project Life ◽  
Wag Injection

The Water Alternating Gas (WAG) process is a cyclic method of injecting alternating cycles of gas followed by water and repeating this process over a number of cycles. WAG injection is to improve oil recovery, by both increasing the macroscopic and microscopic sweep efficiency and to help maintain the reservoir pressure. Also, WAG injection is to postpone the gas breakthrough. The WAG process provides mobility control in fast zones which extends gas project life and oil recovery. This paper provided a comprehensive literature study about  WAG injection. This  paper has collected most of the requirements of the petroleum engineers that has to know about the WAG injection started from basic concepts until the design parameter for WAG injection.   Keywords: Enhanced oil recovery, WAG injection  

Pilot Project Evaluating WAG Efficiency for Carbonate Reservoir in Eastern Siberia

2021 ◽  
Author(s):  
Valentina Zharko ◽  
Dmitriy Burdakov
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Oil Production ◽  
Pilot Project ◽  
Carbonate Reservoir ◽  
Recovery Factor ◽  
Eastern Siberia ◽  
Water Cut ◽  
Wag Injection ◽  
Injection Rates

Abstract The paper presents the results of a pilot project implementing WAG injection at the oilfield with carbonate reservoir, characterized by low efficiency of traditional waterflooding. The objective of the pilot project was to evaluate the efficiency of this enhanced oil recovery method for conditions of the specific oil field. For the initial introduction of WAG, an area of the reservoir with minimal potential risks has been identified. During the test injections of water and gas, production parameters were monitored, including the oil production rates of the reacting wells and the water and gas injection rates of injection wells, the change in the density and composition of the produced fluids. With first positive results, the pilot area of the reservoir was expanded. In accordance with the responses of the producing wells to the injection of displacing agents, the injection rates were adjusted, and the production intensified, with the aim of maximizing the effect of WAG. The results obtained in practice were reproduced in the simulation model sector in order to obtain a project curve characterizing an increase in oil recovery due to water-alternating gas injection. Practical results obtained during pilot testing of the technology show that the injection of gas and water alternately can reduce the water cut of the reacting wells and increase overall oil production, providing more efficient displacement compared to traditional waterflooding. The use of WAG after the waterflooding provides an increase in oil recovery and a decrease in residual oil saturation. The water cut of the produced liquid decreased from 98% to 80%, an increase in oil production rate of 100 tons/day was obtained. The increase in the oil recovery factor is estimated at approximately 7.5% at gas injection of 1.5 hydrocarbon pore volumes. Based on the received results, the displacement characteristic was constructed. Methods for monitoring the effectiveness of WAG have been determined, and studies are planned to be carried out when designing a full-scale WAG project at the field. This project is the first pilot project in Russia implementing WAG injection in a field with a carbonate reservoir. During the pilot project, the technical feasibility of implementing this EOR method was confirmed, as well as its efficiency in terms of increasing the oil recovery factor for the conditions of the carbonate reservoir of Eastern Siberia, characterized by high water cut and low values of oil displacement coefficients during waterflooding.

scholarly journals An evaluation on mechanisms of miscibility development in acid gas injection for volatile oil reservoirs

2019 ◽  
Vol 74 ◽  
pp. 59 ◽  
Author(s):  
Erhui Luo ◽  
Zifei Fan ◽  
Yongle Hu ◽  
Lun Zhao ◽  
Jianjun Wang
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Simulation Method ◽  
Carbonate Reservoir ◽  
Gas Oil ◽  
Oil Composition ◽  
Acid Gas ◽  
Compositional Model ◽  
Injection Process ◽  
Acid Gas Injection

Produced gas containing the acid gas reinjection is one of the effective enhanced oil recovery methods, not only saving costs of disposing acid gases and zero discharge of greenhouse gases but also supporting reservoir pressure. The subsurface fluid from the Carboniferous carbonate reservoir in the southern margin of the Pre-Caspian basin in Central Asia has low density, low viscosity, high concentrations of H2S (15%) and CO2 (4%), high solution gas/oil ratio. The reservoir is lack of fresh water because of being far away onshore. Pilot test has already been implemented for the acid gas reinjection. Firstly, in our work a scheme of crude oil composition grouping with 15 compositions was presented on the basis of bottomhole sampling from DSTs of four wells. After matching PVT physical experiments including viscosity, density and gas/oil ratio and pressure–temperature (P–T) phase diagram by tuning critical properties of highly uncertain heavy components, the compositional model with phase behavior was built under meeting accuracy of phase fitting, which was used to evaluate mechanism of miscibility development in the acid gas injection process. Then using a cell-to-cell simulation method, vaporizing and/or condensing gas drive mechanisms were investigated for mixtures consisting of various proportions of CH4, CO2 and H2S in the gas injection process. Moreover, effects of gas compositions on miscible mechanisms have also been determined. With the aid of pressure-composition diagrams and pseudoternary diagrams generated from the Equation of State (EoS), pressures of First Contact Miscibility (FCM) and Multiple Contact Miscibility (MCM) for various gases mixing with the reservoir oil sample under reservoir temperature were calculated. Simulation results show that pressures of FCM are higher than those of MCM, and CO2 and H2S are able to reduce the miscible pressure. At the same time, H2S is stronger. As the CH4 content increases, both pressures of FCM and MCM are higher. But incremental values of MCM decrease. In addition, calculated envelopes of pseudoternary diagrams for mixtures of CH4, CO2 and H2S gases of varying composition with acid gas injection have features of bell shape, hourglass shape and triangle shape, which can be used to identify vaporizing and/or condensing gas drives. Finally, comparison of the real produced gas and the one deprived of its C3+ was performed to determine types of miscibility and calculate pressures of FCM and MCM. This study provides a theoretical guideline for selection of injection gas to improve miscibility and oil recovery.

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.

Fluid Characterization for Miscible EOR Projects and CO2 Sequestration

2007 ◽  
Vol 10 (05) ◽  
pp. 482-488 ◽  
Author(s):  
Kristian Jessen ◽  
Erling Halfdan Stenby
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Reservoir Simulation ◽  
Co2 Sequestration ◽  
Gas Injection ◽  
Numerical Diffusion ◽  
Injection Process ◽  
Wide Range ◽  
Multicomponent Gas ◽  
The Impact

Summary Accurate performance prediction of miscible enhanced-oil-recovery (EOR) projects or CO2 sequestration in depleted oil and gas reservoirs relies in part on the ability of an equation-of-state (EOS) model to adequately represent the properties of a wide range of mixtures of the resident fluid and the injected fluid(s). The mixtures that form when gas displaces oil in a porous medium will, in many cases, differ significantly from compositions created in swelling tests and other standard pressure/volume/temperature (PVT) experiments. Multicontact experiments (e.g., slimtube displacements) are often used to condition an EOS model before application in performance evaluation of miscible displacements. However, no clear understanding exists of the impact on the resultant accuracy of the selected characterization procedure when the fluid description is subsequently included in reservoir simulation. In this paper, we present a detailed analysis of the quality of two different characterization procedures over a broad range of reservoir fluids (13 samples) for which experimental swelling-test and slimtube-displacement data are available. We explore the impact of including swelling-test and slimtube experiments in the data reduction and demonstrate that for some gas/oil systems, swelling tests do not contribute to a more accurate prediction of multicontact miscibility. Finally, we report on the impact that use of EOS models based on different characterization procedures can have on recovery predictions from dynamic 1D displacement calculations. Introduction During the past few decades, a significant effort has been invested in the studies and development of improved-oil-recovery processes. From a technical point of view, gas injection can be a very efficient method for improving the oil production, particularly in the case when miscibility develops during the displacement process. The lowest pressure at which a gas should be injected into the reservoir to obtain the multicontact miscible displacement—the minimum miscibility pressure (MMP)—has consequently attained a very important status in EOR studies. Various methods for measuring and calculating the MMP have been proposed in the literature. Many of these are based on simplifications such as the ternary representation of the compositional space. This method fails to honor the existence of a combined mechanism controlling the development of miscibility in real reservoir fluids. Zick (1986) and Stalkup (1987) described the existence of the condensing/vaporizing mechanism. They showed that the development of miscibility (MMP) in multicomponent gas-displacement processes could, independent of the mechanism controlling the development of miscibility, be predicted accurately by 1D compositional simulations. A semianalytical method for predicting the MMP was later presented by Wang and Orr (1997), who played an important role in the development and application of the analytical theory of gas-injection processes. Jessen et al. (1998) subsequently developed an efficient algorithm for performing these calculations, reducing the MMP calculation time to a few seconds even for fluid descriptions of 10 components or more. Later, Jessen et al. (2001) used this approach to generate approximate solutions to the dispersion-free, 1D-displacement problem for multicomponent gas-injection processes. Analytical and numerical methods for predicting the performance of a gas-injection process depend on an EOS to predict the phase behavior of the mixtures that form in the course of a displacement process. The role of the phase behavior in relation to numerical diffusion in compositional reservoir simulation has been pointed out previously by Stalkup (1990) and by Stalkup et al. (1990). Recently, Jessen et al. (2004) proposed a method to quantify the interplay of the phase behavior and numerical diffusion in a finite-difference simulation of a gas-injection process. By analyzing the phase behavior of the injection-gas/reservoir-fluid system, a measure of the impact, referred to as the dispersive distance, can be calculated. The dispersive distance is useful when designing and interpreting large-scale compositional reservoir simulations.

scholarly journals Core-scale sensitivity study of CO2 foam injection strategies for mobility control, enhanced oil recovery, and CO2 storage

2020 ◽  
Vol 146 ◽  
pp. 02002
Author(s):  
Zachary Paul Alcorn ◽  
Sunniva B. Fredriksen ◽  
Mohan Sharma ◽  
Tore Føyen ◽  
Connie Wergeland ◽  
...  
Keyword(s):  
Steady State ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Co2 Storage ◽  
Sensitivity Study ◽  
Mobility Control ◽  
Wettability Alteration ◽  
Injection Strategy ◽  
Gravity Effects

This paper presents experimental and numerical sensitivity studies to assist injection strategy design for an ongoing CO2 foam field pilot. The aim is to increase the success of in-situ CO2 foam generation and propagation into the reservoir for CO2 mobility control, enhanced oil recovery (EOR) and CO2 storage. Un-steady state in-situ CO2 foam behavior, representative of the near wellbore region, and steady-state foam behavior was evaluated. Multi-cycle surfactant-alternating gas (SAG) provided the highest apparent viscosity foam of 120.2 cP, compared to co-injection (56.0 cP) and single-cycle SAG (18.2 cP) in 100% brine saturated porous media. CO2 foam EOR corefloods at first-contact miscible (FCM) conditions showed that multi-cycle SAG generated the highest apparent foam viscosity in the presence of refined oil (n-Decane). Multi-cycle SAG demonstrated high viscous displacement forces critical in field implementation where gravity effects and reservoir heterogeneities dominate. At multiple-contact miscible (MCM) conditions, no foam was generated with either injection strategy as a result of wettability alteration and foam destabilization in presence of crude oil. In both FCM and MCM corefloods, incremental oil recoveries were on average 30.6% OOIP regardless of injection strategy for CO2 foam and base cases (i.e. no surfactant). CO2 diffusion and miscibility dominated oil recovery at the core-scale resulting in high microscopic CO2 displacement. CO2 storage potential was 9.0% greater for multi-cycle SAGs compared to co-injections at MCM. A validated core-scale simulation model was used for a sensitivity analysis of grid resolution and foam quality. The model was robust in representing the observed foam behavior and will be extended to use in field scale simulations.

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.

Practical Upscaling Process for Enhanced Water Alternating Gas : A Numerical Investigation

2021 ◽  
Author(s):  
Saeed Majidaie ◽  
Luky Hendraningrat ◽  
M Azri Bin Hanifah
Keyword(s):  
Numerical Investigation ◽  
Scale Up ◽  
Gas Injection ◽  
Differential Pressure ◽  
Laboratory Analysis ◽  
Mobility Control ◽  
Base Case ◽  
Gas Dispersion ◽  
Water Alternating Gas ◽  
Mobility Reduction

Abstract Water alternating gas (WAG) is a well-known strategy to improve the mobility issues during gas injection. However, WAG was identified still having some challenges during implementation at oilfield with high reservoir heterogeneity and high permeable zones in the reservoir and will cause unfavorable mobility ratio. Enproperties of the selected core samplehancement of WAG (EWAG) using foam and surfactant has been research to solve its issue and has success stories. This paper will describe the work process of EWAG to be Pilot at Malaysian oilfield, focusing on numerical investigation during upscaling process. Foam treatment has role for gas mobility control, delaying gas breakthrough and diverting gas to unswept zones. Meanwhile, the surfactant was utilized to reduce the IFT between gas and liquid to enable gas dispersion into liquid phase. An in-house foaming surfactant has been developed and used for coreflooding experiment at harsh environment. It was used to generate stable foam in contact with gas and it caused a mobility reduction which was suitable for mobilizing trapped oil and hence improving oil recovery. Coreflood experiment was performed on native core and all experimental results were consolidated and checked for the quality prior model calibration in the reservoir simulator. Once coreflood model was constructed, base case was run using default foam parameters. It aimed initially to test whether the model run smoothly and to observe the matching quality using the default values. Once satisfactory matchings were achieved, the process continued with foam parameters upscaling. During scale-up process the velocity of the fluids and pressure drop were conserved as laboratory data. The important scale-up parameters and the corresponding scale-up ratio were investigated. Mobility Reduction Factor (MRF) was calculated by dividing average DP for each foam cycle with base differential pressure (DP) in the prior gas injection. MRF values for both lower and higher rate show increasing MRF values. Regardless, these values are lower in lower flowrates sequences compared to ones for higher flowrates. This corresponds to MRF values calculated in the laboratory analysis. Therefore, stronger and more stabilized foam were generated using higher injection rates. Lower and higher flowrates had distinctive set of foam parameters. The acceptable matches for differential pressure, oil, water, and gas were achieved. for lower flowrate. Based on this study, model was able to capture production trends depicted in the laboratory analysis. The foam parameter set from higher flowrates have more potential for further upscaling and modeling in full-field scale.

Using Polymer Alternating Gas to Maximize CO2 Flooding Performance

2014 ◽  
Author(s):  
W.. Li ◽  
D. S. Schechter
Keyword(s):  
Oil Recovery ◽  
Polymer Flooding ◽  
Combination Method ◽  
New Combination ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Sweep Efficiency ◽  
The North ◽  
Carbon Dioxide Co2 ◽  
Wag Injection

Abstract Carbon dioxide (CO2) has been used commercially to recover oil from reservoirs by enhanced oil recovery (EOR) technologies for over 40 years. Currently, CO2 flooding is the second most applied EOR processes in the world behind steamflooding. Water alternating gas (WAG) injection has been a popular method to control mobility and improve volumetric sweep efficiency for CO2 flooding. The average improved recovery is about 9.7%, with a range of 6 to 20% for miscible WAG injection. Despite all the success of WAG injection, sweep efficiency during CO2 flooding is typically a challenge to reach higher oil recovery and better apply the technology. This paper proposes a new combination method called polymer alternating gas (PAG) to improve the volumetric sweep efficiency of the WAG process. The feature of this new method is that polymers are added to water during the WAG process to improve mobility ratio. In the PAG process, polymer flooding and immiscible/miscible CO2 injection are combined. To analyze the feasibility of PAG, models considering both miscible and polymer flooding processes are built to study the performance of PAG. In this paper, the sensitivity of polymer adsorption and concentration are studied. The feasibility of PAG in reservoirs with different permeabilities, different Dykstra-Parsons permeability variation coefficients (VDPs), and different fluids are also studied. A reservoir model from a typical section of the North Burbank Unit (NBU) is used to compare the performance between PAG, WAG, and polymer flooding. This study demonstrates that PAG can significantly improve recovery for immiscible/miscible flooding in homogeneous or heterogeneous reservoirs.

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