Mechanisms of Oil Recovery via Multi-Contact Miscible Gas Injection Process within Lensed Systems

2008 ◽  
Author(s):  
Yahya Mansoor Al-Wahaibi ◽  
Carlos Atilio Grattoni
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Injection Process ◽  
Miscible Gas Injection

Technological Features of Associated Petroleum Gas Miscible Injection MGI in Order to Increase Oil Recovery at a Remote Group of Fields in Western Siberia

2021 ◽  
Author(s):  
Sergey Anatolevich Vershinin ◽  
Alexander Nikolaevich Blyablyas ◽  
Dmitriy Aleksandrovich Golovanov ◽  
Artem Vitalievich Penigin ◽  
Nikolay Grigorievich Glavnov
Keyword(s):  
Oil Recovery ◽  
Western Siberia ◽  
Gas Injection ◽  
Alternative Methods ◽  
Gas Treatment ◽  
Associated Petroleum Gas ◽  
Injection Process ◽  
Gas Utilization ◽  
Underground Reservoir ◽  
Miscible Gas Injection

Abstract The problem of associated petroleum gas utilization is especially urgent for fields located far from infrastructure facilities for raw gas transportation and treatment. For such fields, alternative methods of gas utilization, especially gas re-injection, are becoming relevant. The re-injection options include: injection into underground reservoir for storage (if there are reservoirs suitable for injection near the field), injection into a gas cap, if any, or injection into a productive reservoir. The latter method allows, along with solving the problem of gas disposal, to increase oil recovery. This study describes an example of miscible gas injection into the reservoir at the Chatylkinskoye field, the infrastructure assumptions which make this option a better one versus a selling option, and the features of a gas treatment and injection process.

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 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.

Minimum Miscibility Pressure of CO2/Hydrocarbon Systems Within Nanopores

2021 ◽  
Author(s):  
Gang Yang ◽  
Xiaoli Li
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Unconventional Reservoirs ◽  
Minimum Miscibility Pressure ◽  
Theoretical Approaches ◽  
Fluid Systems ◽  
Confined Fluid ◽  
Miscible Gas Injection ◽  
Fluid Characterization ◽  
The Impact

Abstract Minimum miscibility pressure (MMP), as a key parameter for the miscible gas injection enhanced oil recovery (EOR) in unconventional reservoirs, is affected by the dominance of nanoscale pores. The objective of this work is to investigate the impact of nanoscale confinement on MMP of CO2/hydrocarbon systems and to compare the accuracy of different theoretical approaches in calculating MMP of confined fluid systems. A modified PR EOS applicable for confined fluid characterization is applied to perform the EOS simulation of the vanishing interfacial tension (VIT) experiments. The MMP of multiple CO2/hydrocarbon systems at different pore sizes are obtained via the VIT simulations. Meanwhile, the multiple mixing cell (MMC) algorithm coupled with the same modified PR EOS is applied to compute the MMP for the same fluid systems. Comparison of these results to the experimental values recognize that the MMC approach has higher accuracy in determining the MMP of confined fluid systems. Moreover, nanoscale confinement results in the drastic suppression of MMP and the suppression rate increases with decreasing pore size. The drastic suppression of MMP is highly favorable for the miscible gas injection EOR in unconventional reservoirs.

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.

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