A Model for Spontaneous Imbibition as a Mechanism for Oil Recovery in Fractured Reservoirs

Andersen, Pål Østebø; Evje, Steinar; Kleppe, Hans

doi:10.1007/s11242-013-0246-7

Cited by 71 publications

(31 citation statements)

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“…This implies that in the experimental setup, the matrix surfaces covered by wetting and nonwetting phases do not change during the process. There are other cases in which the recovery performance of a matrix block or a stack of matrix blocks under advancing wetting phase level in the fracture system has been studied (Parsons and Chaney, 1966;Pooladi-Darvish and Firoozabadi, 2000b;Karimaie et al, 2006;Karimaie and Torsaeter, 2007;Qasem et al, 2008;Andersen et al, 2014).…”

Section: A C C E P T E D Accepted Manuscriptmentioning

confidence: 99%

Experimental study of some important factors on nonwetting phase recovery by cocurrent spontaneous imbibition

Hamidpour

Mirzaei‐Paiaman

Masihi

et al. 2015

Journal of Natural Gas Science and Engineering

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Section: A C C E P T E D Accepted Manuscriptmentioning

confidence: 99%

Experimental study of some important factors on nonwetting phase recovery by cocurrent spontaneous imbibition

Hamidpour

Mirzaei‐Paiaman

Masihi

et al. 2015

Journal of Natural Gas Science and Engineering

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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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“…This can be seen as follows. Equation (8) for the Green function g ω (x, t) can be nondimensionalized by scaling x = x L ω / √ 2 and t = t ω t with L ω and t ω given by (19) and (18). Thus we obtain for the Green function the governing equation…”

Section: The Memory Functionmentioning

confidence: 99%

“…Thus, the complex spatial structure of the fracture network is represented in an effective way as an equivalent porous medium, while the slower processes in the secondary continua participate in the average mass transfer in terms of non-local sink-source terms. Com- [19] or can be simplified using transfer functions or the multirate mass transfer (MRMT) approach.…”

Section: Introductionmentioning

confidence: 99%

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Multi-rate mass transfer modeling of two-phase flow in highly heterogeneous fractured and porous media

Tecklenburg

Neuweiler

Carrera

et al. 2016

Advances in Water Resources

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A Model for Spontaneous Imbibition as a Mechanism for Oil Recovery in Fractured Reservoirs

Cited by 71 publications

References 50 publications

Experimental study of some important factors on nonwetting phase recovery by cocurrent spontaneous imbibition

Experimental study of some important factors on nonwetting phase recovery by cocurrent spontaneous imbibition

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

Multi-rate mass transfer modeling of two-phase flow in highly heterogeneous fractured and porous media

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