Thermodynamics of Multiphase Flow in Unconventional Liquids-Rich Reservoirs

Firincioglu, Tuba; Özkan, Erdal; Ozgen, Chet

doi:10.2118/159869-ms

Cited by 53 publications

(26 citation statements)

References 24 publications

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“…al. (1996), Brusilovsky (1990), Firoozabadi (1999, Shapiro & Stanby (1996), Nagy (2002), Didar & Akkutlu (2013), Pang et al (2012), Devegowda et al (2012), Firincioglu et al (2012). In authors opinion the condition of necessary to form continuous liquid phase is oil wettability.…”

Section: State Of the Art Of Research Of Vle In The Porous Mediamentioning

confidence: 99%

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Confined Phase Envelope of Gas-Condensate Systems in Shale Rocks

Nagy¹,

Siemek²

2014

Archives of Mining Sciences

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KRZYWA NASYCENIA UKŁADÓW GAZOWO-KONDENSATOWYCH W NANOPOROWYCH SKAŁACHNatural gas from shales (NGS) and from tight rocks are one of the most important fossil energy resource in this and next decade. Significant increase in gas consumption, in all world regions, will be marked in the energy sector. The exploration of unconventional natural gas & oil reservoirs has been discussed recently in many conferences. This paper describes the complex phenomena related to the impact of adsorption and capillary condensation of gas-condensate systems in nanopores. New two phase saturation model and new algorithm for search capillary condensation area is discussed. The algorithm is based on the Modified Tangent Plane Criterion for Capillary Condensation (MTPCCC) is presented. The examples of shift of phase envelopes are presented for selected composition of gas-condensate systems.Keywords: unconventional natural gas, shale gas, gas condensate, capillary condensation, adsorption, phase envelope, nanopores, Blue Gas Gaz ziemny z łupków (NGS) oraz z ze złóż niskoprzepuszczalnych (typu 'tight') staje się jednym z najważniejszych zasobów paliw kopalnych, w tym i następnym dziesięcioleciu. Znaczący wzrost zużycia gazu we wszystkich regionach świata zaznacza się głównie w sektorze energetycznym. Rozpoznawanie niekonwencjonalnych złóż gazu ziemnego i ropy naftowej w ostatnim czasie jest omawiane w wielu konferencjach. Niniejszy artykuł opisuje złożone zjawiska związane z wpływem adsorpcji i kapilarnej kondensacji w nanoporach w złożach gazowo-kondensatowych. Pokazano nowy dwufazowy model równowagowy dwufazowy i nowy algorytm wyznaczania krzywej nasycenia w obszarze kondensacji kapilarnej. Algorytm bazuje na kryterium zmodyfikowanym płaszczyzny stycznej dla kapilarnej kondensacji (MTPCCC). Przykłady zmiany krzywych nasycenia są przedstawiane w wybranym składzie systemów gazowo-kondensatowych Słowa kluczowe: gaz niekonwencjonalny, gaz z łupków, gaz kondensatowy, kondensacja kapilarna,

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Section: State Of the Art Of Research Of Vle In The Porous Mediamentioning

confidence: 99%

“…(2009. ) Diaz et al (2009), Zhang et al 2013, Sanaei et al 2013. Firincioglu et al (2012 have analysed porosity and pore structure of several shale reservoir.…”

Section: State Of the Art Of Research Of Vle In The Porous Mediamentioning

confidence: 99%

Confined Phase Envelope of Gas-Condensate Systems in Shale Rocks

Nagy¹,

Siemek²

2014

Archives of Mining Sciences

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“…An example of Kelvin's propane vapor pressure calculation when confined to a 10 nm pore (Firoozabadi, 2012) is depicted in Figure 7 along with its vapor pressure behavior as a function of temperature in a bulk cell showing the significant impact of interfacial curvature. In a multicomponent mixture, in addition to the usual thermodynamic variables such as pressure, temperature and fluid composition, the capillary effects (Leveret 1941, Sigmund et al 1973, Durmishian et al 1964, Tindy 1966, Lee 1989) and surface forces (Najobaei et al 2012 andFirincioglu et al 2012) strongly influence the fluid behavior. The saturation pressure observed in bulk cells is suppressed significantly in a nanopore environment, the magnitude of which depends on the interfacial curvature controlled by the pore/throat size.…”

Section: Thermodynamics and Fluid Phase Behavior In Nano-poresmentioning

confidence: 99%

The Critical Role of Rock and Fluid in Unconventional Shale Reservoir Performance

Nagarajan

Honarpour

Arasteh

2013

Unconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013

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Unconventional hydrocarbon resources are changing the world energy picture. Fluid, rock and rock-fluid properties play a key role in developing and managing unconventional reservoirs and their long-term performance. The complexity of rockfluid properties and their strong interdependence in shale reservoirs make it difficult to characterize fluid flow in nano-Darcy reservoirs. Furthermore, fluid thermodynamics and flow characterization physics in nanopore systems differ significantly from those encountered in conventional reservoirs. To generate reliable reservoir performance predictions, PVT models should account for the impact of high capillary pressures and/or surface forces encountered in nanopores. Flow modeling should accurately capture fluid distribution and compositional variability in the pore system as well as multiphase flow characteristics in a wide range of pore/pore-throat size wettability. This paper presents a methodology for:1.Characterizing key rock and fluid parameters and their uncertainties through laboratory and Lattice-Boltzmann simulations. 2. Characterizing the impact of these parameters on performance prediction through parametric reservoir simulation studies on a sector model. The impact of bubble point pressure suppression and the associated viscosity, oil formation volume factor (VF) and solution gas oil ratio (GOR) changes on reservoir performance was captured through sensitivity studies in the simulation. Relative permeability models were developed based on pore-level flow simulation through Lattice-Boltzmann. These models were further scaled-up to the end-point relative permeability data from core measurements.A sector model consisting of a network of hydraulic and natural fractures embedded in the matrix was built to study the sensitivities of fluid and rock properties such as bubble point suppression, the altered PVT property behavior, relative permeability, capillary pressure, and the matrix and fracture properties. Sensitivity runs allowed for comparisons of relative performance predictions of initial rates and ultimate recovery, impacted by the critical rock and fluid data, including: effective permeability, its alignment with the hydraulic and natural fracture network, rock-type based compaction, unconventional PVT behavior (e.g., suppressed oil bubble point pressure and the resultant viscosity and GOR behavior), interfacial tension (IFT) and capillary pressure, and relative permeability.

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“…The increase in recovery was mainly attributed to longer gas-free production in their paper. Firincioglu et al (2012) calculated formation volume factors affected by capillary pressure and also recognized that bubble-point pressure is decreased. The main results of their paper were the calculation of formation volume factors in the presence of capillary pressure.…”

Section: Introductionmentioning

confidence: 99%

“…They also observed an increase in oil production caused by capillary pressure. Alharthy et al (2013) made dual-porosity simulations where they applied the method based on the purecomponent correlations for shifting the critical properties developed by Singh et al (2009). Firincioglu et al (2012 developed a correlation to calculate bubble-point pressure suppression as a function of capillary pressure and solution gas-oil ratio.…”

Section: Introductionmentioning

confidence: 99%

Effect of large gas-oil capillary pressure on production: A compositionally-extended black oil formulation

Nojabaei

Siripatrachai

Johns

et al. 2016

Journal of Petroleum Science and Engineering

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a b s t r a c tPore sizes are typically on the order of nanometers for many shale and tight rock oil reservoirs. Such small pores can affect the phase behavior of in situ oil and gas owing to large capillary pressure. Current black-oil simulation practice is to alter the unconfined black-oil data for a fixed mean pore size to generate confined black-oil data with a suppressed bubble-point pressure. This approach ignores compositional effects on interfacial tension and the impact of pore-size distribution (PSD) with variable phase saturations on capillary pressure and phase behavior.In this paper, we develop a compositionally-extended black-oil model where we solve the compositional equations (gas, oil, and water components) directly so that black-oil data are a function of gas content in the oleic phase and gas-oil capillary pressure. The principle unknowns in the variable bubblepoint fully-implicit formulation are oil pressure, overall gas composition, and water saturation. Flash calculations in the model are non-iterative and are based on K-values calculated explicitly from the blackoil data. The advantage of solving the black-oil model using the compositional equations is to increase robustness of the simulations owing to a variable bubble-point pressure that is a function of two parameters; gas content and capillary pressure. Leverett J-functions measured for the Bakken reservoir are used to establish the effective pore size-P c -saturation relationship, where the effective pore size depends on gas saturation, which is the non-wetting phase saturation. The input fluid data to the simulator, e.g. interfacial tension (IFT), phase densities and viscosities, are pre-calculated as functions of pressure from the Peng-Robinson equation of state (PREOS) for three fixed pore sizes. During the simulation, at any pressure and saturation, fluid properties are calculated at the effective pore radius by using linear interpolation between these three data sets. We compare the results of the compositionallyextended black oil model with those of a fully-implicit eight-component compositional model that we have also developed. The results for the Bakken reservoir show that including PSD in the model can increase estimated recoveries by nearly 10% for initially undersaturated reservoirs while the increase can be over 100% for initially saturated reservoirs. Capillary pressure significantly increases the original oilin-place (OOIP) for reservoirs that would otherwise be initially saturated leading to larger oil production.

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Thermodynamics of Multiphase Flow in Unconventional Liquids-Rich Reservoirs

Cited by 53 publications

References 24 publications

Confined Phase Envelope of Gas-Condensate Systems in Shale Rocks

Confined Phase Envelope of Gas-Condensate Systems in Shale Rocks

The Critical Role of Rock and Fluid in Unconventional Shale Reservoir Performance

Effect of large gas-oil capillary pressure on production: A compositionally-extended black oil formulation

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