In-Situ Investigation of Aging Protocol Eﬀect on Relative Permeability Measurements Using High- Throughput Experimentation Methods

Mascle, Matthieu; Youssef, S.; Deschamps, H.; Vizika, O.

doi:10.30632/pjv60n4-2019a5

Cited by 6 publications

(8 citation statements)

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“…Nonetheless, it was determined that 3 h was sufficient time to obtain equilibrium adhesion, and this is in accordance with similar experiments performed elsewhere on brine composition effects on rock-oil interactions in carbonate reservoirs [23]. The short time frame makes force spectroscopy provide benefits of efficiency when compared to previous wettability evaluation methods that require days to weeks to obtain statistically tangible and reliable results due to the need for aging and steady state requirement [46,47].…”

Section: Methodssupporting

confidence: 84%

Insights into Nanoscale Wettability Effects of Low Salinity and Nanofluid Enhanced Oil Recovery Techniques

2020

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In this study, enhanced oil recovery (EOR) techniques—namely low salinity and nanofluid EOR—are probed at the nanometer-scale using an atomic force microscope (AFM). Mica substrates were used as model clay-rich rocks while AFM tips were coated to present alkyl (-CH3), aromatic (-C6H5) and carboxylic acid (-COOH) functional groups, to simulate oil media. We prepared brine formulations to test brine dilution and cation bridging effects while selected concentrations (0 to 1 wt%) of hydrophilic SiO2 nanoparticles dispersed in 1 wt% NaCl were used as nanofluids. Samples were immersed in fluid cells and chemical force mapping was used to measure the adhesion force between polar/non-polar moieties to substrates. Adhesion work was evaluated based on force-displacement curves and compared with theories. Results from AFM studies indicate that low salinity waters and nanoparticle dispersions promote nanoscale wettability alteration by significantly reducing three-phase adhesion force and the reversible thermodynamic work of adhesion, also known as adhesion energy. The maximum reduction in adhesion energy obtained in experiments was in excellent agreement with existing theories. Electrostatic repulsion and reduced non-electrostatic adhesion are prominent surface forces common to both low salinity and nanofluid EOR. Structural forces are complex in nature and may not always decrease total adhesion force and energy at high nanoparticle concentration. Wettability effects also depend on surface chemical groups and the presence of divalent Mg2+ and Ca2+ cations. This study provides fresh insights and fundamental information about low salinity and nanofluid EOR while demonstrating the application of force-distance spectroscopy in investigating EOR techniques.

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Section: Methodssupporting

confidence: 84%

Insights into Nanoscale Wettability Effects of Low Salinity and Nanofluid Enhanced Oil Recovery Techniques

2020

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Section: Discussionmentioning

confidence: 99%

“…According to our assessment, long-time aged cores have up to 10% of pore space affected by increased deposition, which is an acceptable trade-off for the conveniently small sample size. A good account on a difference between aging at static and flowing conditions can be found in Mascle et al 99 Paramagnetic relaxation enhancement due to oxygen dissolved in sample fluids affects both EPR and NMR responses. Interaction between free radicals of oil components and oxygen diradicals decrease the spin−lattice relaxation time, which lead to the EPR resonance linewidth broadening.…”

Section: ■ Discussionmentioning

confidence: 99%

On the Optimum Aging Time: Magnetic Resonance Study of Asphaltene Adsorption Dynamics in Sandstone Rock

2019

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Wettability is a key factor defining ultimate hydrocarbon recovery. Extensive experimentation is required to replicate the wetting state of reservoir rocks. This involves a rock sample wettability restoration procedure, including an aging step and a concept of an optimum aging time, in which asphaltene chemistry plays a major role. There are numerous reports on significance of various crude oil components and elements of asphaltene structure to their tendency to interact with the solid phase, though subject evidence is contradictory. We investigate a possible relationship between the composition of oil, kinetics of an aging process, and a change of sandstone rock wettability. Wettability state of the cores was monitored using low-field NMR relaxometry. The composition and key components of accumulated deposits were established by matching 1H solution-state NMR and X-band EPR spectra of deposits to the spectra of SARA (saturates-aromatics-resins-asphaltenes) fractions of aging fluids. We determined adsorption rate as a function of aging fluid type, monitored free radical and vanadyl content of deposits, and wettability state (through surface relaxivity) over extended aging time interval. EPR data suggest no correlation between the concentration of free radicals in deposits and wettability of the cores. We observe two distinctive periods in the aging process: (i) early-time adsorption best described by a pseudo-second-order kinetic model similar for all aging fluids used in this study, suggesting a common reaction-limited process; (ii) a late-time adsorption process of a faster rate proportional to a bulk diffusion coefficient of aging fluids approximated by an intraparticle diffusion kinetic model. The transition time interval between the two can be used as a definition of an “optimum aging time” in special core analysis. Results provide a link between oil chemistry and wettability phenomena in rocks and may contribute to the development of a model predicting wettability reversal and more accurate reservoir modeling.

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“…An increasing dP during the flooding simply requires having a relative permeabilities contrast that overrides the unfavorable viscosity ratio: k rom /k rwm > l o /l w = 4. This condition is easily met for strongly water-wet cores [33,35]. The piston-like displacement allows to use a 1D two-phases flow simulator to simulate this coreflood.…”

Section: Differential Pressure Monitoringmentioning

confidence: 99%

“…The coreflood CF1 has shown a situation where an unfavorable mobility ratio was overridden by favorable relative permeabilities curves (kr-curves), resulting in a favorable fluids mobility and a stable displacement. This result would probably not have been observed for this viscosity ratio after ageing the core, as the kr-curves are no longer favorable for the oil-phase [33,35]. A possible improvement to scale the digitation behavior for different wettability systems could be to use a mobility ratio that integrates the fluids relatives permeabilities.…”

Section: Water Breakthrough Versus Dimensional Numbersmentioning

confidence: 99%

Investigation of waterflood front digitations during immiscible displacements in porous media

Mascle

Rosenberg

Roboele

et al. 2021

Oil Gas Sci. Technol. – Rev. IFP Energies nouvelles

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In this work, unstable displacements were conducted using special equipment designed to run in-situ CT-scanner experiments. All the displacements were conducted on a homogeneous Bentheimer sandstone plug, of 10 cm in diameter and 40 cm in length. Digitations (or fingering) have been observed under varying conditions of injection flowrate, displaced fluid viscosity, and core wettability. They have been characterized at both the core scale, using the core average oil saturation and the water breakthrough; and at the local scale, using the local saturations and had-hoc image processing analysis. It was found that the effect of the different flowing conditions on the front digitations could not be interpreted independently. The oil recovery at brine breakthrough showed a good correlation with the viscous fingering number for the water-wet case. However, a different scaling was observed for the oil-wet case. The interplay of the different flowing conditions mitigates the possibility of constructing a unique scaling number to account for all experimental condition. The local saturation monitoring has provided a new insight to characterize the finger shapes and analyze the production mechanisms. It allowed to distinguish two independent contributions to early breakthrough: viscous dominated digitations and capillary dominated digitations. A two-phases diagram has been constructed to plot and compare these contributions for all flowing conditions. Their evolutions show the main production mechanisms during the flooding. We observed that the viscous digitations were not causing phase trapping at core scale: the core is completely swept after breakthrough. For the water-wet case, we found that the local oil recovery of swept zone remained constant before and after breakthrough while for the oil-wet case it is improving during all the water flooding process.

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In-Situ Investigation of Aging Protocol Eﬀect on Relative Permeability Measurements Using High- Throughput Experimentation Methods

Cited by 6 publications

References 0 publications

Insights into Nanoscale Wettability Effects of Low Salinity and Nanofluid Enhanced Oil Recovery Techniques

Insights into Nanoscale Wettability Effects of Low Salinity and Nanofluid Enhanced Oil Recovery Techniques

On the Optimum Aging Time: Magnetic Resonance Study of Asphaltene Adsorption Dynamics in Sandstone Rock

Investigation of waterflood front digitations during immiscible displacements in porous media

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