Effect of Nano-Scale Pore Size Distribution on Fluid Phase Behavior of Gas IOR in Shale Reservoirs

2018 ◽  
Author(s):  
Sheng Luo ◽  
Jodie L. Lutkenhaus ◽  
Hadi Nasrabadi
Keyword(s):  
Pore Size Distribution ◽  
Phase Behavior ◽  
Pore Size ◽  
Size Distribution ◽  
Fluid Phase ◽  
Nano Scale ◽  
Shale Reservoirs

Effect of Nanoscale Pore-Size Distribution on Fluid Phase Behavior of Gas-Improved Oil Recovery in Shale Reservoirs

SPE Journal ◽  
2020 ◽  
Vol 25 (03) ◽  
pp. 1406-1415
Author(s):  
Sheng Luo ◽  
Jodie L. Lutkenhaus ◽  
Hadi Nasrabadi
Keyword(s):  
Pore Size Distribution ◽  
Phase Behavior ◽  
Pore Size ◽  
Size Distribution ◽  
Oil Recovery ◽  
Gas Injection ◽  
Fluid Phase ◽  
Improved Oil Recovery ◽  
Nanoscale Pore ◽  
Shale Reservoirs

Summary The improved oil recovery (IOR) of unconventional shale reservoirs has attracted much interest in recent years. Gas injection, such as carbon dioxide (CO2) and natural gas, is one of the most considered techniques for its sweep efficiency and effectiveness in low-permeability reservoirs. However, the uncertainties of fluid phase behavior in shale reservoirs pose a great challenge in evaluating the performance of a gas-injection operation. Shale reservoirs typically have macroscale to nanoscale pore-size distribution in the porous space. In fractures and macropores, the fluid shows bulk behavior, but in nanopores, the phase behavior is significantly altered by the confinement effect. The integrated behavior of reservoir fluids in this complex environment remains uncertain. In this study, we investigate the nanoscale pore-size-distribution effect on the phase behavior of reservoir fluids in gas injection for shale reservoirs. A case of Anadarko Basin shale oil is used. The pore-size distribution is discretized as a multiscale system with pores of specific diameters. The phase equilibria of methane injection into the multiscale system are calculated. The constant-composition expansions are simulated for oil mixed with various fractions of injected gas. It is found that fluid in nanopores becomes supercritical with injected gas, but lowering the pressure to less than the bubblepoint turns it into the subcritical state. The bubblepoint is generally lower than the bulk and the degree of deviation depends on the amount of injected gas. The modeling of confined-fluid swelling shows that fluid swelled from nanopores is predicted to contain more oil than the swelled fluid at bulk state.

scholarly journals Pore-Scale Simulation of Confined Phase Behavior with Pore Size Distribution and Its Effects on Shale Oil Production

Energies ◽  
2021 ◽  
Vol 14 (5) ◽  
pp. 1315
Author(s):  
Jingwei Huang ◽  
Hongsheng Wang
Keyword(s):  
Phase Equilibrium ◽  
Equation Of State ◽  
Pore Size Distribution ◽  
Phase Behavior ◽  
Pore Size ◽  
Size Distribution ◽  
Critical Role ◽  
Shale Oil ◽  
Pore Scale ◽  
Modified Equation

Confined phase behavior plays a critical role in predicting production from shale reservoirs. In this work, a pseudo-potential lattice Boltzmann method is applied to directly model the phase equilibrium of fluids in nanopores. First, vapor-liquid equilibrium is simulated by capturing the sudden jump on simulated adsorption isotherms in a capillary tube. In addition, effect of pore size distribution on phase equilibrium is evaluated by using a bundle of capillary tubes of various sizes. Simulated coexistence curves indicate that an effective pore size can be used to account for the effects of pore size distribution on confined phase behavior. With simulated coexistence curves from pore-scale simulation, a modified equation of state is built and applied to model the thermodynamic phase diagram of shale oil. Shifted critical properties and suppressed bubble points are observed when effects of confinement is considered. The compositional simulation shows that both predicted oil and gas production will be higher if the modified equation of state is implemented. Results are compared with those using methods of capillary pressure and critical shift.

scholarly journals Probe material choice for nuclear magnetic resonance cryoporometry (NMRC) measurements of the nano-scale pore size distribution of unconventional reservoirs

2018 ◽  
Vol 37 (1) ◽  
pp. 412-428
Author(s):  
Feng Zhu ◽  
Wenxuan Hu ◽  
Jian Cao ◽  
Biao Liu ◽  
Yifeng Liu ◽  
...  
Keyword(s):  
Nuclear Magnetic Resonance ◽  
Magnetic Resonance ◽  
Pore Size Distribution ◽  
Porous Materials ◽  
Pore Size ◽  
Size Distribution ◽  
Geological Samples ◽  
Nano Scale ◽  
Chloride Hexahydrate ◽  
Nuclear Magnetic

Nuclear magnetic resonance cryoporometry is a newly developed technique that can characterize the pore size distribution of nano-scale porous materials. To date, this technique has scarcely been used for the testing of unconventional oil and gas reservoirs; thus, their micro- and nano-scale pore structures must still be investigated. The selection of the probe material for this technique has a key impact on the quality of the measurement results during the testing of geological samples. In this paper, we present details on the nuclear magnetic resonance cryoporometric procedure. Several types of probe materials were compared during the nuclear testing of standard nano-scale porous materials and unconventional reservoir geological samples from Sichuan Basin, Southwest China. Gas sorption experiments were also carried out on the same samples simultaneously. The KGT values of the probe materials octamethylcyclotetrasiloxane and calcium chloride hexahydrate were calibrated using standard nano-scale porous materials to reveal respective values of 149.3 Knm and 184 Knm. Water did not successfully wet the pore surfaces of the standard controlled pore glass samples; moreover, water damaged the pore structures of the geological samples, which was confirmed during two freeze-melting tests. The complex phase transition during the melting of cyclohexane introduced a nuclear magnetic resonance signal in addition to that from liquid in the pores, which led to an imprecise characterization of the pore size distribution. Octamethylcyclotetrasiloxane and calcium chloride hexahydrate have been rarely employed as nuclear magnetic resonance cryoporometric probe materials for the testing of an unconventional reservoir. Both of these materials were able to characterize pore sizes up to 1 μm, and they were more applicable than either water or cyclohexane.

Porosity and pore size distribution of shales: a case study of the Carynginia Formation, Perth Basin, Western Australia

2017 ◽  
Vol 57 (2) ◽  
pp. 660
Author(s):  
M. Nadia Testamanti ◽  
Reza Rezaee ◽  
Jie Zou
Keyword(s):  
Pore Size Distribution ◽  
Pore Size ◽  
Size Distribution ◽  
Gas Adsorption ◽  
Pore Network ◽  
Pore Sizes ◽  
Wide Range ◽  
Pore Characterisation ◽  
Shale Reservoirs ◽  
Mercury Injection Capillary Pressure

The evaluation of the gas storage potential of shale reservoirs requires a good understanding of their pore network. Each of the laboratory techniques used for pore characterisation can be applied to a specific range of pore sizes; but if the lithology of the rock is known, usually one suitable method can be selected to investigate its pore system. Shales do not fall under any particular lithological classification and can have a wide range of minerals present, so a combination of at least two methods is typically recommended for a better understanding of their pore network. In the laboratory, the Low-Pressure Nitrogen Gas Adsorption (LP-N2-GA) technique is typically used to examine micropores and mesopores, and Mercury Injection Capillary Pressure (MICP) tests can identify pore throats larger than 3 nm. In contrast, a wider range of pore sizes in rock can be screened with Nuclear Magnetic Resonance (NMR), either in laboratory measurements made on cores or through well logging, provided that the pores are saturated with a fluid. The pore network of a set of shale core samples from the Carynginia Formation was investigated using a combination of laboratory methods. The cores were studied using the NMR, LP-N2-GA and MICP techniques, and the experimental porosity and pore size distribution results are presented. When NMR results were calibrated with MICP or LP-N2-GA measurements, then the pore size distribution of the shale samples studied could be estimated.

Effect of Pore-Size Distribution on Phase Transition of Hydrocarbon Mixtures in Nanoporous Media

SPE Journal ◽  
2016 ◽  
Vol 21 (06) ◽  
pp. 1981-1995 ◽  
Author(s):  
Lei Wang ◽  
Xiaolong Yin ◽  
Keith B. Neeves ◽  
Erdal Ozkan
Keyword(s):  
Phase Transition ◽  
Phase Change ◽  
Pore Size Distribution ◽  
Phase Behavior ◽  
Pore Size ◽  
Capillary Pressure ◽  
Size Distribution ◽  
Hydrocarbon Mixtures ◽  
Nanoporous Media ◽  
Light Oil

Summary Pore sizes of many shale-oil and tight gas reservoirs are in the range of nanometers. In these pores, capillary pressure and surface forces can make the phase behavior of hydrocarbon mixtures different from that characterized in pressure/volume/temperature (PVT) cells. Many existing phase-behavior models use a single pore size to describe the effect of confinement on phase behavior. To follow up with our earlier theoretical studies and experimental observations, this research investigates the effect of pore-size distribution. By use of a vapor/liquid equilibrium model that considers the effect of capillary pressure, we present a procedure to simulate the sequence of phase changes in a porous medium caused by a pore-size distribution. This procedure is used to simulate depressurizations of a light oil and a retrograde gas confined inside nanoporous media, the pore-size distributions of which are characteristic of tight reservoirs. The fluid compositions are representative of typical reservoir fluids. Predictions of the model show that phase transition in nanoporous medium with pore-size distribution is not described by a single phase boundary. The initial phase change in the large pores alters the composition of the remaining fluid, and, in turn, suppresses the next phase change. For the two cases studied, models with and without capillary pressure gave similar predictions. For light oil, capillary pressure still noticeably increased the level of supersaturation, and the critical gas saturation had a strong influence on the properties of produced fluids. For retrograde gas, the effect of capillary pressure was insignificant because of the low interfacial tension (IFT). Despite the choice of fluids, calculations indicate that the smallest pores are probably always occupied by hydrocarbon liquid during depressurization.

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