Study on Phase Behavior of CO2/Hydrocarbons in Shale Reservoirs Considering Sieving Effect and Capillary Pressure

2021 ◽  
Author(s):  
Yapeng Tian ◽  
Binshan Ju ◽  
Xudong Wang ◽  
Hongya Wang ◽  
Jie Hu ◽  
...  
Keyword(s):  
Phase Behavior ◽  
Capillary Pressure ◽  
Shale Reservoirs ◽  
Sieving Effect

Thermodynamic Analysis of Phase Behavior at High Capillary Pressure

SPE Journal ◽  
2018 ◽  
Vol 23 (06) ◽  
pp. 1977-1990 ◽  
Author(s):  
Mohsen Rezaveisi ◽  
Kamy Sepehrnoori ◽  
Gary A. Pope ◽  
Russell T. Johns
Keyword(s):  
Phase Behavior ◽  
Capillary Pressure ◽  
Thermodynamic Analysis ◽  
Phase Stability ◽  
Tangent Plane ◽  
General Purpose ◽  
Distance Method ◽  
Capillary Equilibrium ◽  
Production Behavior ◽  
Reservoir Simulator

Summary High capillary pressure has a significant effect on the phase behavior of fluid mixtures. The capillary pressure is high in unconventional reservoirs because of the small pores in the rock, so understanding the effect of capillary pressure on phase behavior is necessary for reliable modeling of unconventional shale-gas and tight-oil reservoirs. As the main finding of this paper, first we show that the tangent-plane-distance method cannot be used to determine phase stability and present a rigorous thermodynamic analysis of the problem of phase stability with capillary pressure. Second, we demonstrate that there is a maximum capillary pressure (Pcmax) where calculation of capillary equilibrium using bulk-phase thermodynamics is possible and derive the necessary equations to obtain this maximum capillary pressure. We also briefly discuss the implementation of the capillary equilibrium in a general-purpose compositional reservoir simulator. Two simulation case studies for synthetic gas condensate reservoirs were performed to illustrate the influence of capillary pressure on production behavior for the fluids studied.

Modeling Phase Behavior of Nano-Confined Fluids in Shale Reservoirs with A Modified Soave-Redlich-Kwong Equation of State

2021 ◽  
pp. 133661
Author(s):  
Peng Wang ◽  
Shijun Huang ◽  
Fenglan Zhao ◽  
Jin Shi ◽  
Bin Wang ◽  
...  
Keyword(s):  
Equation Of State ◽  
Phase Behavior ◽  
Confined Fluids ◽  
Shale Reservoirs

Nanopore Compositional Modeling in Unconventional Shale Reservoirs

2016 ◽  
Vol 19 (03) ◽  
pp. 415-428 ◽  
Author(s):  
Najeeb S. Alharthy ◽  
Tadesse W. Teklu ◽  
Thanh N. Nguyen ◽  
Hossein Kazemi ◽  
Ramona M. Graves
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Flow Characteristics ◽  
Gas Production ◽  
Eagle Ford ◽  
Compositional Modeling ◽  
Shale Reservoirs ◽  
Behavior Shift

Summary Understanding the mechanism of multicomponent mass transport in the nanopores of unconventional reservoirs, such as Eagle Ford, Niobrara, Woodford, and Bakken, is of great interest because it influences long-term economic development of such reservoirs. Thus, we began to examine the phase behavior and flow characteristics of multicomponent flow in primary production in nanoporous reservoirs. Besides primary recovery, our long-term objectives included enhanced oil production from such reservoirs. The first step was to evaluate the phase behavior in nanopores on the basis of pore-size distribution. This was motivated because the physical properties of hydrocarbon components are affected by wall proximity in nanopores as a result of van der Waals molecular interactions with the pore walls. For instance, critical pressure and temperature of hydrocarbon components shift to lower values as the nanopore walls become closer. In our research, we applied this kind of critical property shift to the hydrocarbon components of two Eagle Ford fluid samples. Then, we used the shifted phase characteristics in dual-porosity compositional modeling to determine the pore-to-pore flow characteristics, and, eventually, the flow behavior of hydrocarbons to the wells. In the simulation, we assigned three levels of phase behavior in the matrix and fracture pore spaces. In addition, the flow hierarchy included flow from matrix (nano-, meso-, and macropores) to macrofractures, from macrofractures to a hydraulic fracture (HF), and through the HF to the production well. From the simulation study, we determined why hydrocarbon fluids flow so effectively in ultralow-permeability shale reservoirs. The simulation also gave credence to the intuitive notion that favorable phase behavior (phase split) in the nanopores is one of the major reasons for production of commercial quantities of light oil and gas from shale reservoirs. It was determined that the implementation of confined-pore and midconfined-pore phase behavior lowers the bubblepoint pressure, and this, in turn, leads to a slightly higher oil recovery and lesser gas recovery. Also it was determined that the implementation of midconfined-pore and confined-pore phase-behavior shift reduces the retrograde liquid-condensation region, which in turn, leads to lower liquid yield while maintaining the same gas-production quantity. Finally, the important reason that we are able to produce shale reservoirs economically is “rubblizing” the reservoir matrix near HFs, which creates favorable permeability pathways to improve reservoir drainage. This is why multistage hydraulic fracturing is so critical for successful development of shale reservoirs.

scholarly journals Influence of Adsorption and Capillary Pressure on Phase Equilibria inside Shale Reservoirs

2018 ◽  
Vol 32 (3) ◽  
pp. 2819-2833 ◽  
Author(s):  
Diego R. Sandoval ◽  
Wei Yan ◽  
Michael L. Michelsen ◽  
Erling H. Stenby
Keyword(s):  
Phase Equilibria ◽  
Capillary Pressure ◽  
Shale Reservoirs

Effect of Gas/Oil Capillary Pressure on Minimum Miscibility Pressure for Tight Reservoirs

SPE Journal ◽  
2019 ◽  
Vol 25 (02) ◽  
pp. 820-831 ◽  
Author(s):  
Kaiyi Zhang ◽  
Bahareh Nojabaei ◽  
Kaveh Ahmadi ◽  
Russell T. Johns
Keyword(s):  
Capillary Pressure ◽  
Hyperbolic Equations ◽  
Fluid Pressure ◽  
Gas Oil ◽  
Minimum Miscibility Pressure ◽  
Tight Reservoir ◽  
Tie Lines ◽  
Tight Reservoirs ◽  
Shale Reservoirs ◽  
The Impact

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 (k < 200 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 k > 200 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 CO2-MMP 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.

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