Equation-of-State-Based Downhole Fluid Characterization

Zuo, Julian Y.; Zhang, Dan; Dubost, Francois Xavier; Dong, Chengli; Mullins, Oliver C.; O'Keefe, Michael; Betancourt, Soraya S.

doi:10.2118/114702-pa

Cited by 16 publications

(4 citation statements)

References 36 publications

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“…We chose two unconventional reservoir fluids, Eagle Ford shale gas and Wolfcamp shale oil, to test the aforementioned framework and algorithm. The characterization procedure of Zuo and Zhang and Zuo et al was utilized to characterize the reservoir fluids, and the SKR EOS was used to describe the phase behavior of the reservoir fluids. The characterized compositions and critical properties of the reservoir fluids are given in the Appendix.…”

Section: Resultsmentioning

confidence: 99%

Impact of Capillary Pressure and Nanopore Confinement on Phase Behaviors of Shale Gas and Oil

Zuo¹,

Guo

Liu

et al. 2018

Energy Fuels

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In this paper, a general framework of theoretical models and algorithm is developed to predict phase envelopes (saturation points) and quality lines of shale gas and oil in nanopores. The equation of state (EOS) and the modified Young− Laplace equation are used to take into consideration the effect of phase behavior and capillary pressure on phase envelopes, respectively. The Zuo and Stenby parachor model is applied to determine interfacial tensions between the vapor and liquid phases. In addition, a critical property shift of pure components is utilized to account for the impact of nanopore confinement on phase envelopes. The algorithm has proven to be robust for generating phase envelopes including critical points, cricondentherms (maximum temperatures), and cricondenbars (maximum pressures) for a variety of fluids at different compositions, vapor mole fractions (quality lines), and pore sizes. The models and algorithm are then used to explain the recently measured data of normal boiling point or bubble point temperatures for pure n-heptane in type I kerogen, binary mixtures of n-pentane + n-hexane and n-pentane + n-heptane, and a ternary mixture of n-pentane + n-hexane + n-heptane in the nanofluidic devices. For pure n-heptane in type I kerogen, with a presumption of nanopores being completely wetted by the liquid phase, the models agree well with the experimental data within a reasonable range of type I kerogen nanopore distributions in the presence of capillary pressure effect only as well as both capillary pressure and nanopore confinement effects. However, for the binary and ternary mixtures in the nanofluidic devices, the complete wettability assumption seems no longer valid. The wetting fluid−wall interaction parameter (λ) is then adjusted to match the experimental data at the nanopore radius of 5 nm. The adjusted parameters are λ = −142.2 ∼ −167.5 and λ = −14.0 for the three tested binary and ternary mixtures in the presence of capillary pressure effect only as well as both capillary pressure and nanopore confinement effects, respectively. The models provide not only good predictions at other radii but also a correct trend for the mixtures in the presence of capillary pressure effect only but a wrong trend against the experimental data in the presence of both capillary pressure and nanopore confinement effects. In addition, in the presence of both capillary pressure and confinement effects, a decrease in bubble and dew point pressures with decreasing pore radius is observed for shale gas and oil. For gas condensate mixtures, field production data show that produced liquid and gas ratios decrease even at reservoir pressures above bulk retrograde dew points. It is obvious that the model with critical property shift contradicts the field observation. More research activities in this area are required. Although in the presence of capillary pressure effect only, a decrease in bubble point pressures is estimated for shale oil, an increase in dew point pressures is predicted for shale gas with decreasing pore ...

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Section: Resultsmentioning

confidence: 99%

Impact of Capillary Pressure and Nanopore Confinement on Phase Behaviors of Shale Gas and Oil

Zuo¹,

Guo

Liu

et al. 2018

Energy Fuels

Self Cite

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“…The EoS method can be used to describe all the components except asphaltene. At the same time, asphaltene can be divided into five pseudosegments by gamma function and characterized by three parameters. , On the basis of the optical logging curve obtained by DFA, the composition distribution of asphaltene is acquired by the molar mass. This methodology can be used to evaluate reservoir connectivity and compartmentalization accurately …”

Section: Asphaltene Stability and Modelingmentioning

confidence: 99%

Status and Outlook of Oil Field Chemistry-Assisted Analysis during the Energy Transition Period

et al. 2022

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Analytical chemistry is powerful in analyzing complex mixtures of crude oil and brine subsurfaces on the basis of atomic and molecular levels. Geochemistry applies chemical principles and experiments to understand earth science and engineering problems. Crude oil's molecule structure, especially for the resin and asphaltenes, could only be understood using advanced analytical chemistry techniques. Fingerprinting geochemistry applied for conventional and unconventional reservoirs helps better identify hydrocarbon resources. Subsequently, the reservoir fluid geodynamics (RFG) discipline is promoted because of the gap between the basin modeling and reservoir simulation models with geochemistry data. Fluid migration could be elaborated from the geological time when the reservoir trap was formed to nowadays with the span of millions of years. Also, asphaltene geochemistry data could be used to delineate reservoir compartmentalization. This work reviews the state-of-art theory and technology of analytical chemistry and geochemistry applied in the upstream oil and gas industry and proposes an improvement of high-resolution chemistry power for efficient and sustainable energy development.

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“…Due to the constraint of material pressure capacity, it is difficult to observe the entire gas migration directly. Sampling tubes are designed for better observation of gas migration as the downhole fluid sampling equipment [34,35]. The sampling probes are inserted at a specific location with designed depth in the longitudinal section.…”

Section: Experimental Model Designmentioning

confidence: 99%

A Novel Assisted Gas–Oil Countercurrent EOR Technique for Attic Oil in Fault-Block Reservoirs

Jiang

et al. 2020

Energies

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As the mature oil fields have stepped into the high water cut stage, the remaining oil is considered as potential reserves, especially the attic oil in the inclined fault-block reservoirs. A novel assisted gas–oil countercurrent technique utilizing gas oil countercurrent (GOC) and water flooding assistance (WFA) is proposed in this study to enhance the remaining oil recovery in sealed fault-block reservoirs. WFA is applied in our model to accelerate the countercurrent process and inhibit the gas channeling during the production process. Four comparative experiments are conducted to illustrate enhanced oil recovery (EOR) mechanisms and compare the production efficiency of assisted GOC under different assistance conditions. The results show that WFA has different functions at different stages of the development process. In the gas injection process, WFA forces the injected gas to migrate upward and shortens the shut-in time by approximately 50% and the production efficiency improves accordingly. Compared with the basic GOC process, the attic oil swept area is extended 60% at the same shut-in time condition and secondary gas cap forms under the influence of WFA. At the production stage, the WFA and secondary gas cap expansion form the bi-directional flooding. The bi-directional flooding also displaces the bypassed oil and replaced attic oil located below the production well, which cannot be swept by the gas cap expansion. WFA inhibits the gas channeling effectively and increases the sweep factor by 26.14% in the production stage. The oil production increases nearly nine times compared with the basic GOC production process. The proposed technique is significant for the development of attic oil in the mature oil field at the high water cut stage.

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Equation-of-State-Based Downhole Fluid Characterization

Cited by 16 publications

References 36 publications

Impact of Capillary Pressure and Nanopore Confinement on Phase Behaviors of Shale Gas and Oil

Impact of Capillary Pressure and Nanopore Confinement on Phase Behaviors of Shale Gas and Oil

Status and Outlook of Oil Field Chemistry-Assisted Analysis during the Energy Transition Period

A Novel Assisted Gas–Oil Countercurrent EOR Technique for Attic Oil in Fault-Block Reservoirs

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