Experimental Conditions Favoring the Formation of Fluid Banks during Counter-Current Flow in Porous Media

Karpyn, Zuleima T.; Li, G.; Grader, A.S.; Halleck, P.M.

doi:10.1007/s11242-005-0617-9

Cited by 12 publications

(8 citation statements)

References 6 publications

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“…We note also that experiments performed by Templeton et al (1961), and more recently by Karpyn et al (2006), started from an initial water saturation profile that was essentially constant throughout the column. The observed final profiles seem to confirm qualitatively our computational results for the present theory, reported already in Hilfer (2006c), Hilfer and Doster (2010), and Doster et al (2010).…”

Section: Resultsmentioning

confidence: 76%

Nonmonotone Saturation Profiles for Hydrostatic Equilibrium in Homogeneous Porous Media

Hilfer

Doster

Zegeling

2012

Vadose Zone Journal

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Recently, the observation of nonmonotonicity of traveling wave solutions for saturation profiles during constant‐flux infiltration experiments has highlighted the shortcomings of the traditional, seventy year old mathematical model for immiscible displacement in porous media. Several recent modifications have been proposed to explain these observations. The present paper suggests that nonmonotone saturation profiles might occur even at zero flux. Specifically, nonmonotonicity of saturation profiles is predicted for hydrostatic equilibrium, when both fluids are at rest. It is argued that in traditional theories with the widely used single‐valued monotone constitutive functions, nonmonotone profiles should not exist in hydrostatic equilibrium. The same applies to some modifications of the traditional theory. Nonmonotone saturation profiles in hydrostatic equilibrium arise within a generalized theory that contains the traditional theory as a special case. The physical origin of the phenomenon is simultaneous occurrence of imbibition and drainage. It is argued that indications for nonmonotone saturation profiles in hydrostatic equilibrium might have been observed in past experiments and could become clearly observable in a closed column experiment.

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Section: Resultsmentioning

confidence: 76%

Nonmonotone Saturation Profiles for Hydrostatic Equilibrium in Homogeneous Porous Media

Hilfer

Doster

Zegeling

2012

Vadose Zone Journal

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“…The literature reports similar observations from gravity-driven countercurrent flow experiments, in which drainage, imbibition, and middle transition zones are identified. [11][12][13] Fig.5 also show uneven movement of the invading water front, due mainly to rock heterogeneities and boundary effects. The wavy water front is caused by capillary contrast in the rock layers, which are aligned perpendicular to the fracture.…”

Section: Experimental Observationsmentioning

confidence: 97%

Fracture-Matrix Transport Dominated by Capillary-Driven Flow in Layered Sandstone

Karpyn¹,

Halleck²,

Grader³

2006

SPE/DOE Symposium on Improved Oil Recovery

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractFluid transport in reservoir formations under quasi-static conditions is strongly dominated by capillary forces. These forces are a macroscopic manifestation of complex molecular interactions between fluids and solids inside the intricate pore structure of rocks.In naturally fractured reservoirs, spontaneous capillary imbibition is an important recovery mechanism since waterflooding of the disjointed matrix cannot be accomplished by forced displacement.The goal of the present experimental work is to establish a detailed reference case for the validation of numerical models of capillary-driven flow in fractured formations. This paper presents experimental results of two-phase capillary-driven flow in a layered Berea sandstone sample with a single longitudinal fracture. The sample was artificially fractured using a modified Brazilian test that resulted in an extensional longitudinal fracture oriented perpendicularly to the natural bedding planes of the rock. Non-destructive high-resolution X-ray CT imaging allowed identification of localized cocurrent and countercurrent flow during spontaneous capillary imbibition.Three distinctive flow intervals were identified during spontaneous imbibition. Those are early, intermediate, and late time. The presence of bedding planes in the rock's structure determines the shape of the imbibing front during early-time imbibition. The imbibing front advances faster through low porosity/permeability layers due to higher capillary forces. Cross-layer fluid exchange tends to level the imbibing front during the intermediate imbibition stage. Countercurrent flow controls fluid transport during the early and intermediate intervals, while both cocurrent and countercurrent flow mechanisms coexist at late time. Results from this experimental work present strong evidence of localized hysteretic behavior. Drainage, imbibition, and transition zones characteristic of countercurrent flow are clearly identified as a function of time.

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“…They found the "fluid bank" existed at the top of the tube. Karpyn et al [25] investigated factors that affect the formation of "fluid bank" in the countercurrent flow process by CT scan and reservoir simulation. Base on the conventional reservoir type classification, the "gas bank" located at the top of the model is called the secondary gas cap in this paper [26].…”

Section: Introductionmentioning

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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Experimental Conditions Favoring the Formation of Fluid Banks during Counter-Current Flow in Porous Media

Cited by 12 publications

References 6 publications

Nonmonotone Saturation Profiles for Hydrostatic Equilibrium in Homogeneous Porous Media

Nonmonotone Saturation Profiles for Hydrostatic Equilibrium in Homogeneous Porous Media

Fracture-Matrix Transport Dominated by Capillary-Driven Flow in Layered Sandstone

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

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