Analytical Solutions for Linear Counter-Current Spontaneous Imbibition in the Frontal Flow Period

Li, Y.

doi:10.1007/s11242-010-9656-y

Cited by 20 publications

(11 citation statements)

References 14 publications

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“…However, the fluid flow patterns under AFO boundary conditions are complex even for homogeneous porous media, which results in that it is very difficult to simulate process of fluid flow by mathematical models. In recent years, many research groups started to focus on the SI under OEO and TEO boundary conditions (Ruth et al, 2007;Li, 2011;Mirzaei-Paiaman et al, 2011;Ruth and Arthur, 2011).…”

Section: Completely Counter-current Imbibitionmentioning

confidence: 99%

A critical review on fundamental mechanisms of spontaneous imbibition and the impact of boundary condition, fluid viscosity and wettability

Meng

Liu

Wang

2017

Adv. Geo-Energ. Res.

115

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Spontaneous imbibition (SI) is one of the primary mechanisms of oil production from matrix system in fractured reservoirs. The main driving force for SI is capillary pressure. Researches relating to SI are moving fast. In the past few years, amount of literature on the development of SI with respect to many variables, such as mechanism of imbibition, scaling of imbibition data and wettability of matrix blocks. In this review, we first introduced the fundamental physics mechanism of SI through capillary tube models and micromodels. Then both conventional and more novel experimental methods of measuring oil production are discussed thoughtfully. This is followed by reviewing the oil production performance under various boundary conditions and the characteristic length in scaling equations that have been used to account for different cores shape and boundary conditions. The effect of fluid viscosity on the rate of oil production and final oil recovery as well as the development of viscosity term in the scaling equation are reported. The commonly used methods to quantitatively evaluate the wettability of cores and the SI under mix-and oil-wet conditions are introduced. And last but not least, the methods and mechanism of wettability alteration for enhanced oil recovery in mix-or oil-wet fractured reservoirs are presented.Keywords: Spontaneous imbibition, fractured reservoirs, boundary condition, viscosity ratio, wettability.Citation: Meng, Q., Liu, H., Wang, J. A critical review on fundamental mechanisms of spontaneous imbibition and the impact of boundary condition, fluid viscosity and wettability.

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Section: Completely Counter-current Imbibitionmentioning

confidence: 99%

A critical review on fundamental mechanisms of spontaneous imbibition and the impact of boundary condition, fluid viscosity and wettability

Meng

Liu

Wang

2017

Adv. Geo-Energ. Res.

115

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“…Also, production does not vary linearly with the square root of time. The second most-popular core geometry is One End Open (OEO); considerable effort has gone into modelling imbibition for this geometry (Ruth et al 2007;Schmid and Geiger 2012;Li 2011;Andersen et al 2014). For linear imbibition, a relatively straightforward mathematical analysis predicts that the volume of oil produced will depend on the square root of time.…”

Section: Introductionmentioning

confidence: 99%

The Effect of Viscosity on Relative Permeabilities Derived from Spontaneous Imbibition Tests

et al. 2014

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Spontaneous imbibition experiments are usually carried out on All Faces Open or One End Open cores and this severely limits the information that can be obtained because imbibition can be approximately described with a square root of time function, which involves only a single variable. Two Ends Open with one end in contact with the brine and the other end in contact with oil (at the same pressure) offers much more varied behaviour because imbibition is partly co-current and partly counter-current. Previously, an analysis and experiments were described for primarily co-current imbibition when the viscosities of the oil and brine were close to equal. Small deviations from the square root of time relationship allowed parameters such as the capillary back pressure (bubble pressure) to be determined. In the present paper, the situation when the oil is significantly more viscous than the brine is analysed and compared with experiments. The results show that counter-current imbibition continues for almost the entire imbibition period. They also show that the relative permeability to oil behind the front varies as the viscosity ratio is changed. Very viscous oil gives higher relative permeability than less viscous oil. ACross-sectional area of cylindrical core (m 2 ) D Parameter involved in the ratio of co-current to counter-current production of non-wetting phase k nw Co-current relative permeability to the non-wetting phase ahead of the imbibition front k * nw Counter-current relative permeability to the non-wetting phase behind the imbibition front k w Co-current relative permeability to the wetting phase behind the imbibition front K Rock permeability (m 2 ) L core Length of cylindrical core (m) P c,f Capillary pressure at the imbibition front (Pa) P c,o Capillary back pressure at the core face in contact with wetting phase (Pa) P w,f Pressure in the wetting phase at the imbibition front (Pa) P nw,f Pressure in the non-wetting phase at the imbibition front (Pa) P nw,pt (t)Pressure in the non-wetting phase measured at the pressure port at time t q nw Co-current flow of the non-wetting phase (m 3 /s) q * nw Counter-current flow of the non-wetting phase (m 3 /s) q w Co-current flow of the wetting phase (m 3 ) S wi Initial wetting phase saturation S wf Wetting phase saturation behind the front t Time for the front to reach distance X f from the core face in contact with the wetting phase (s) V nw (t)Cumulative volume of oil produced co-currently at time t (m 3 ) V * nw (t) Cumulative volume of oil produced counter-currently at time t (m 3 ) V w (t)Cumulative volume of water that has entered the core co-currently at time t (m 3 ) V * w (t) Cumulative volume of water that has entered the core counter-currently at time t (m 3

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“…Li et al introduced the measurement of the end pressure during the restricted and unrestricted counter-current spontaneous imbibitions in order to measure the frontal capillary pressures and calculate the back capillary pressures (Li et al 2006;Ligthelm et al 2009). Recently, Li obtained the analytical solutions of counter-current spontaneous imbibition in the frontal flow period (Li 2011). Since then, the determination of contact angles as a function of pore sizes inside a core has become possible, as long as a comparison of the capillary pressures is made between the core under investigation and a very strongly water-wet core with the same lithology and initial water saturation (Fig.…”

Section: Fundamentals In Secondary Oil Recoverymentioning

confidence: 99%

Oil Recovery by Low Salinity Water Injection into a Reservoir: A New Study of Tertiary Oil Recovery Mechanism

2011

Transp Porous Med

Self Cite

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Low salinity water injections for oil recovery have shown seemingly promising results in the case of clay-bearing sandstones saturated with asphaltic crude oil. Reported data showed that low salinity water injection could provide up to 20% pore volume (PV) of additional oil recovery for core samples and up to 25% PV for reservoirs in near wellbore regions, compared with brine injection at the same Darcy velocity. The question remains as to whether this additional recovery is also attainable in reservoirs. The answer requires a thorough understanding of oil recovery mechanism of low salinity water injections. Numerous hypotheses have been proposed to explain the increased oil recovery using low salinity water, including migration of detached mixed-wet clay particles with absorbed residual oil drops, wettability alteration toward increased water-wetness, and emulsion formation. However, many later reports showed that a higher oil recovery associated with low salinity water injection at the common laboratory flow velocity was neither necessarily accompanied by migration of clay particles, nor necessarily accompanied by emulsion. Moreover, increased water-wetness has been shown to cause the reduction of oil recovery. The present study is based on both experimental and theoretical analyses. Our study reveals that the increased oil recovery is only related to the reduction of water permeability due to physical plugging of the porous network by swelling clay aggregates or migrating clay particles and crystals. At a fixed apparent flow velocity, the value of negative pressure gradient along the flow path increases as the water permeability decreases. Some oil drops and blobs can be mobilized under the increased negative pressure gradient and contribute to the additional oil recovery. Based on the revealed mechanism, we conclude that low salinity water injection cannot be superior to brine injection in any clay-bearing sandstone reservoir at the maximum permitted injection pressure. Through our study of low salinity water injection, the theory of tertiary oil recovery has been notably improved. Keywords

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Analytical Solutions for Linear Counter-Current Spontaneous Imbibition in the Frontal Flow Period

Cited by 20 publications

References 14 publications

A critical review on fundamental mechanisms of spontaneous imbibition and the impact of boundary condition, fluid viscosity and wettability

A critical review on fundamental mechanisms of spontaneous imbibition and the impact of boundary condition, fluid viscosity and wettability

The Effect of Viscosity on Relative Permeabilities Derived from Spontaneous Imbibition Tests

Oil Recovery by Low Salinity Water Injection into a Reservoir: A New Study of Tertiary Oil Recovery Mechanism

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