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Collaborating Authors
Nojabaei, Bahareh
Effect of Gas/Oil Capillary Pressure on Minimum Miscibility Pressure for Tight Reservoirs
Zhang, Kaiyi (Virginia Polytechnic Institute and State University) | Nojabaei, Bahareh (Virginia Polytechnic Institute and State University) | Ahmadi, Kaveh (Pometis Technology) | Johns, Russell T. (Pennsylvania State University)
Summary Shale and tight reservoir rocks have pore throats on the order of nanometers, and, subsequently, a large capillary pressure. When the permeability is ultralow (kโ<โ200 nd), as in many shale reservoirs, diffusion might dominate over advection, so that the gas injection might no longer be controlled by the multicontact minimum miscibility pressure (MMP). For gasfloods in tight reservoirs, where kโ>โ200 nd and capillary pressure is still large, however, advection likely dominates over diffusive transport, so that the MMP once again becomes important. This paper focuses on the latter case to demonstrate that the capillary pressure, which has an impact on the fluid pressure/volume/temperature (PVT) behavior, can also alter the MMP. The results show that the calculation of the MMP for reservoirs with nanopores is affected by the gas/oil capillary pressure, owing to alteration of the key tie lines in the displacement; however, the change in the MMP is not significant. The MMP is calculated using three methods: the method of characteristics (MOC); multiple mixing cells; and slimtube simulations. The MOC method relies on solving hyperbolic equations, so the gas/oil capillary pressure is assumed to be constant along all tie lines (saturation variations are not accounted for). Thus, the MOC method is not accurate away from the MMP but becomes accurate as the MMP is approached when one of the key tie lines first intersects a critical point (where the capillary pressure then becomes zero, making saturation variations immaterial there). Even though the capillary pressure is zero for this key tie line, its phase compositions (and, hence, the MMP) are impacted by the alteration of all other key tie lines in the composition space by the gas/oil capillary pressure. The reason for the change in the MMP is illustrated graphically for quaternary systems, in which the MMP values from the three methods agree well. The 1D simulations (typically slimtube simulations) show an agreement with these calculations as well. We also demonstrate the impact of capillary pressure on CO2โMMP for real reservoir fluids. The effect of large gas/oil capillary pressure on the characteristics of immiscible displacements, which occur at pressures well below the MMP, is discussed.
- North America > United States > Texas (1.00)
- Europe (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract Molecular diffusion plays an important role in oil and gas migration and transport in tight shale formations. However, there are insufficient reference data in the literature to specify the diffusion coefficients within a porous media. This study aims at calculating diffusion coefficients of shale gas, shale condensate, and shale oil at reservoir conditions with CO2 injection for EOR/EGR. The large nano-confinement effects including large gas-oil capillary pressure and critical property shifts on diffusion coefficient are examined. An effective diffusion coefficient that describes the diffusion behavior in a tight porous solid is estimated by using tortuosity-porosity relations as well as the measured shale tortuosity from 3D imaging techniques. The results indicated that nano - confinement could affect the diffusion behavior through altering the phase properties, such as phase compositions and densities. Compared to bulk phase diffusivity, the effective diffusion coefficient in a porous shale rock is reduce by 10 to 10 times as porosity decreases from 0.1 to 0.03.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Huron Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (18 more...)
Effect of Pore Size Heterogeneity on Hydrocarbon Fluid Distribution and Transport in Nanometer-Sized Porous Media
Zhang, Kaiyi (Virginia Polytechnic Institute and State University) | Du, Fengshuang (Virginia Polytechnic Institute and State University) | Nojabaei, Bahareh (Virginia Polytechnic Institute and State University)
Abstract In this paper, we investigate the effect of pore size heterogeneity on multicomponent multiphase hydrocarbon fluid composition distribution and its subsequent influence on mass transfer through shale nano-pores. We use a compositional simulation model with modified flash calculation, which considers the effect of large gas-oil capillary pressure on phase behavior. We consider different average pore sizes for different segments of the computational domain and investigate the effect of the resulting heterogeneity on phase and composition distributions, and production. A two dimensional formulation is considered here for the application of matrix-fracture cross mass transfer. Note that the rock matrix can also consist of different regions with different average pore sizes. Both convection and molecular diffusion terms are included in the mass balance equations, while different reservoir fluids such as Bakken and Marcellus are considered. The simulation results show that since oil and gas phase compositions depend on the pore size, there is a concentration gradient between the two adjacent pores with different sizes. Considering that shale permeability is small, we expect the mass transfer between two sections of the reservoir/core with two distinct average pore sizes to be diffusion-dominated. This observation implies that there can be a selective matrix-fracture component mass transfer during both primary production and gas injection EOR as a result of confinement-dependent phase behavior. Therefore, molecular diffusion term should be always included in the mass transfer equations, for both primary and gas injection EOR simulation of heterogeneous shale reservoirs.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (6 more...)
A Black-Oil Approach to Model Produced Gas Injection for Enhanced Recovery of Conventional and Unconventional Reservoirs
Du, Fengshuang (Virginia Polytechnic Institute and State University) | Nojabaei, Bahareh (Virginia Polytechnic Institute and State University) | Johns, Russell T. (The Pennsylvania State University)
Abstract In this study, a fast and robust compositionally extended black-oil simulation approach is developed, which is capable of including the effect of large gas-oil capillary pressure for first and multi-contact miscible, and immiscible gas injection. The simulation approach is used to model primary depletion and gas flooding in a high-permeability reservoir using a five-spot flow pattern for different reservoir pressures. The comparison with fully-compositional model shows good agreement. For an initially undersaturated reservoir with both injection and production wells pressures above the original bubble-point pressure, gas evolves near the injection well and it later breaks through the production well as produced gas is injected. Additionally, the primary depletion and huff-n-puff gas injection in tight shale reservoirs by using the compositionally extended black-oil model indicates that the effect of large gas-oil capillary pressure on recovery becomes smaller as reservoir pressure is higher. Finally, a dynamic gas-oil relative permeability correlation that accounts for the compositional changes owing to the produced gas injection is introduced and applied, and its effect on oil recovery is examined.
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation > Middle Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Sanish Field > Bakken Shale Formation (0.99)
- (2 more...)
Minimum Miscibility Pressure Calculation for Oil Shale and Tight Reservoirs With Large Gas-Oil Capillary Pressure
Zhang, Kaiyi (Virginia Polytechnic Institute and State University) | Nojabaei, Bahareh (Virginia Polytechnic Institute and State University) | Ahmadi, Kaveh (Pometis Technology) | Johns, Russell T. (The Pennsylvania State University)
Abstract Shale and tight rocks are associated with tiny pore throats, on the order of nanometers, and subsequently large capillary pressure. The calculation of the minimum miscibility pressure (MMP) in nanopore space is complex because the phase compositions from flash calculations are affected by capillary pressure. This paper examines the effect of capillary pressure on the calculation of MMP using cubic equation-of-state (EOS) and three techniques: the method of characteristics (MOC), multiple mixing cells, and slim tube simulation. Ternary mixtures of hydrocarbons and real reservoir fluids are considered. Using MOC, capillary pressure changes both liquid and vapor compositions and alters the tie lines. The reason for the change in the MMP is illustrated graphically with ternary and quaternary diagrams. The modified slim tube simulation tool is also used to estimate MMPs of CO2 with Bakken and Eagle Ford oil. We use an upgraded flash calculation in the slim tube procedure to estimate MMPs with large capillary pressures for real reservoir fluids. The results show that high capillary pressure changes liquid and vapor phase compositions and this change tends to either decrease or increase the CO2 MMP depending on the original oil composition. The importance of MMP for gas injection in shales as well as the effect of large gas-oil capillary pressure on the characteristics of immiscible floods in shales is discussed. Introduction Unconventional oil and gas resources, such as shale gas, tight oil, and shale oil contribute significantly to hydrocarbon production in North America (Hakimelahi and Jafarpour, 2015). Although strong oil and gas demand and technological progress have led to major unconventional resources production increase in the USA, and worldwide, in recent years, there are still uncertainties in understanding the complex behavior of such reservoirs as reported by Dong et al (2011). Despite multiple research studies in the area, the altered phase behavior of hydrocarbon fluids due to large gas-oil capillary pressure in the confined space of shales and tight rocks is not yet fully understood. Numerous research studies have been conducted to investigate the phase behavior of reservoir fluids in confined space of shale reservoirs. Based on the previous studies by Zarragoicoechea et al (2004) and Singh. et al (2009), the confined space in shale nanopores can alter the phase behavior of petroleum mixtures either by changing the petroleum mixture constituent components critical properties, such as critical pressures and temperatures, or such an alteration can be owing to large gas-oil capillary pressure in confined nanopores which is proposed in the studies by Shapiro et al (2000), Nojabaei, B. et al (2013) and Sugata P. Tan. et al (2015).
- Research Report > New Finding (0.49)
- Research Report > Experimental Study (0.34)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.94)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.94)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.94)
- (3 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract Black-oil fluid properties are determined by lab measurements or can be calculated through flash calculations of the reservoir fluid. Allowing for a variable bubble-point pressure in black- or volatile-oil models requires a table of fluid properties be extended above the original bubble-point. Reservoir simulation accuracy, however, may be affected by discontinuities in the input data and poor predictions of extrapolated fluid properties. Common practice is to add surface gas to the original oil in the lab and increase the pressure to reach a new bubble-point. Another approach is to use linear extrapolation of oil and gas K-values with pressure on a log-log plot, where K-values are equal to 1.0 at a pseudo-critical or convergence pressure. The latter approach results in discontinuities in the phase behavior. We calculate continuous black-oil fluid properties above the original bubble-point by adding a fraction of the equilibrium gas at one bubble-point pressure to achieve a larger bubble-point pressure. This procedure continues until a critical point is reached at the top of the pseudocomponent pressure-composition diagram. Unlike other methods commonly used or recently proposed, the approach provides a smooth and continuous pressure-composition curve to the critical point. The model further allows for reinjection of produced gas, methane, or CO2 to increase oil recovery for both volatile and black oils. We show how to tune the models to the MMP by matching the appropriate critical point pressure. Further, the approach allows the use of black-oil or volatile-oil properties for tight rocks where capillary pressure alters the saturation pressures by decreasing the bubble-point pressure or increasing the dew-point pressure. Bubble-point pressure in the new model is a function of both capillary pressure (effective pore radius) and gas content. The phase behavior is also described on ternary diagrams for up to four components (water, oil, gas, and CO2 or CH4) and three phases (aqueous, oleic, gaseous) to allow for miscible and immiscible injection (or soaking) of various gases. The new phase behavior could be easily incorporated in a compositionally-extended black- or volatile-oil simulator. The approach could also be extended to model gas condensate reservoirs with or without gas injection and capillary pressure.
- North America > United States > North Dakota > Sanish Field > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Elm Coulee Field > Bakken Shale Formation > Middle Bakken Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.98)
- (2 more...)
Summary Diagnostic fracture-injection testing (DFIT) has gained widespread usage in the evaluation of unconventional reservoirs. DFIT entails injection of water above the formation-parting pressure, followed by a long-duration pressure-falloff test. This test is a pragmatic method of gaining critical reservoir information (e.g., the formation-parting pressure, fracture-closure pressure, and initial- reservoir pressure), leading to fracture-completion design and reservoir-engineering calculations. In typical field operations, pressure is measured at the wellhead, not at the bottom of the hole, because of cost considerations. The bottomhole pressure (BHP) is obtained by simply adding a constant hydrostatic head of the water column to the wellhead pressure (WHP) at each timestep. Questions arise whether this practice is sound because of significant changes in temperature that occur in the wellbore, leading to changes in density and compressibility throughout the fluid column. This paper explores this question and offers an analytical model for estimating the transient temperature at a given depth and timestep for computing the BHP. Furthermore, on the basis of the premise of a line-source well, we have shown that the early-time data can be represented by the square-root of time formulation, leading to the new modified Hall relation for the injection period.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)