Scaling of oil recovery by spontaneous imbibition for wide variation in aqueous phase viscosity with glycerol as the viscosifying agent

Fischer, Herbert; Morrow, Norman R.

doi:10.1016/j.petrol.2006.03.003

Cited by 56 publications

(54 citation statements)

References 13 publications

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“…In this section, it is intended to show the acceptable scaling performance of the VSG l w þ ffiffiffiffiffiffiffiffiffiffiffiffi l w l nw p for a wide range of wetting and nonwetting phase viscosities using the published SWW and mixed-wet experimental data of, respectively, Fischer and Morrow (2006) and Tong et al (2002). Fischer and Morrow (2006) performed COUCSI experiments using the cylindrical SWW oil saturated Berea sandstones with zero initial water saturation.…”

Section: Validationmentioning

confidence: 99%

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Incorporation of viscosity scaling group into analysis of MPMS index for laboratory characterization of wettability of reservoir rocks

Mirzaei‐Paiaman

Saboorian‐Jooybari

Masihi

2016

J Petrol Explor Prod Technol

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Wettability is a key parameter affecting petrophysical properties of reservoir rocks. Mirzaei-Paiaman et al. (Energy Fuels 27:7360-7368, 2013) presented an index (referred to as MPMS) for laboratory characterization of wettability of native-or restored-state reservoir rock samples. To use this index two counter-current spontaneous imbibition (COUCSI) experiments are needed, one on the native-or restored-state core sample and another on the strongly water-wet (SWW) reference system. Slope analysis of recovery data in these two systems gives inputs for determination of MPMS index. The two systems must have the same pore structure, initial water saturation, and viscosity ratio. The case of high viscosity reservoir crude needs the reference COUCSI test to be performed using a high viscosity polar compounds-free oil. Such test could be very slow and time consuming. The purpose of this study is to remove the need for limiting condition of the same viscosity ratio between the two systems, so that the reference experiment could be performed using any viscosity ratio independent of viscosity ratio of the native-or restored-state system. Thus, in the case of high viscosity reservoir crude, the reference test can be conducted using a low viscosity oil. Such test is relatively very fast and time efficient. We do this by benefiting the viscosity scaling group (VSG) proposed by Mason et al. (J Pet Sci Eng 72:195-205, 2010). Using experimental data from three sets of mixed-wet systems, we show that applicability of this VSG is not limited to SWW systems only. This VSG is used to relax the need for the limiting condition of the same viscosity ratio between the native-or restored-state and reference systems in the MPMS method. Using two sets of experimental data, we show that acceptable results are observed when comparing the MPMS indices estimated by the proposed technique and the original MPMS method.

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Section: Validationmentioning

confidence: 99%

“…Fischer and Morrow (2006) performed COUCSI experiments using the cylindrical SWW oil saturated Berea sandstones with zero initial water saturation. They used glycerol as the viscosifying agent to vary the wetting phase viscosity.…”

Section: Validationmentioning

confidence: 99%

Incorporation of viscosity scaling group into analysis of MPMS index for laboratory characterization of wettability of reservoir rocks

Mirzaei‐Paiaman

Saboorian‐Jooybari

Masihi

2016

J Petrol Explor Prod Technol

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“…This expression has been recently applied to cores of different shape (Yildez et al, 2006) (Fischer & Morrow, 2006) …”

Section: He2 Cos Wi =0%mentioning

confidence: 99%

“…Two important imbibition geometries, linear and radial inwards into a solid core, have frequently been tested by experiment. It has been observed (Fischer et al 2006) that logarithmic plots of the distance of frontal advance calculated from the fraction imbibed ( f x for linear and ( ) f open R R − for radial) versus time on log-log plots are straight lines. Figure 7-11 shows such plots for the three shape factors.…”

Section: Fractional Productionmentioning

confidence: 99%

Fundamentals of Reservoir Surface Energy as Related to Surface Properties, Wettability, Capillary Action and Oil Recovery from Fractured Reservoirs by Spontaneous Imbibition

Morrow¹,

Fischer²,

Liu³

et al. 2006

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The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition.A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the non-wetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models.In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed-wet rocks. Imbibition measurements will include novel sensitive pressure measurements designed to elucidate the basic mechanisms that determine induction time and drive the very slow rate of spontaneous imbibition commonly observed for mixed-wet rocks. In further demonstration of concepts, three approaches to improved oil recovery from fractured reservoirs will be tested; use of surfactants to promote imbibition in oil wet rocks by wettability alteration: manipulation of injection brine composition: reduction of the capillary back pressure which opposes production of oil at the fracture face.

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“…For the investigation of spontaneous imbibition, the selection of which boundary conditions to apply is a significant problem. The commonly applied boundary conditions include all faces open (AFO) (Fischer and Morrow 2006), two ends closed (TEC) (Fischer and Morrow 2005), one end open (OEO) (Akin et al 2000) and two ends open (TEO) (Mason et al 2010b). The most widely investigated boundary condition for imbibition experiments is AFO because it does not need to seal the core faces.…”

Section: Introductionmentioning

confidence: 99%

Asymmetry Characteristics of Oil Production by Spontaneous Imbibition from Cores with Two Ends Open

et al. 2016

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Spontaneous imbibition experiments with two ends open (TEO) boundary condition showed that oil production from each open face of core is asymmetrical while the invasion of water is symmetrical. Investigating the asymmetry characteristics of oil production is helpful to understand the imbibition displacement mechanisms. In this paper, a mathematical model considering the difference in capillary back pressure for TEO imbibition is established by assuming piston-like advance of the imbibition front. Based on the model, the reason for asymmetry in oil production is discussed and the effect of the viscosity ratio, relative permeability ratio, average capillary back pressure and the difference in capillary back pressure on the asymmetry in oil production is investigated as well. The simulated results show that asymmetry in oil production depends on the ratio of the difference in capillary back pressure to the pressure drop in oil between the imbibition front and the open face of the core. As capillary driving pressure dissipated in oil is very small, a small difference in capillary back pressure will cause a significant asymmetric production of oil. Furthermore, the asymmetry in oil production decreases with increasing viscosity ratio (μ o /μ w ) and relative permeability ratio (k rw /k rnw ) and increases with increasing average capillary back pressure and the difference in capillary back pressure. This work gives us a comprehensive insight into the spontaneous imbibition with TEO boundary condition. Keywords Spontaneous imbibition · Two ends open · Asymmetry in oil production List of symbolsA Cross-sectional area of the core (cm 2 ) k rw,L Relative permeability to wetting phase behind the left imbibition front k rnw,L Relative permeability to non-wetting phase behind the left imbibition front B Qingbang Meng 123 736 Q. Meng et al.k rw,R Relative permeability to wetting phase behind the right imbibition front k rnw,R Relative permeability to non-wetting phase behind the right imbibition front K Absolute permeability (×10 −3 µm 2 ) L Length of the core (cm) P w,L Pressure in the wetting phase at the left imbibition front (atm) P nw,L Pressure in the non-wetting phase at the left imbibition front (atm) P w,R Pressure in the wetting phase at the right imbibition front (atm) P nw,R Pressure in the non-wetting phase at the right imbibition front (atm) P cf,L Capillary driving pressure at the left imbibition front (atm) P cf,R Capillary driving pressure at the right imbibition front (atm) P cb,L Capillary back pressure at the left open face (atm) P cb,R Capillary back pressure at the right open face (atm) q w,L Flow rate of wetting phase behind the left imbibition front (cm 3 /s) q w,R Flow rate of wetting phase behind the right imbibition front (cm 3 /s) q nw,L Flow rate of non-wetting phase behind the left imbibition front (cm 3 /s) q nw,R Flow rate of non-wetting phase behind the right imbibition front (cm 3 /s) q nw,M Flow rate of non-wetting phase across the middle of the core (cm 3 /s) R qw Ratio of water invasion fro...

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Scaling of oil recovery by spontaneous imbibition for wide variation in aqueous phase viscosity with glycerol as the viscosifying agent

Cited by 56 publications

References 13 publications

Incorporation of viscosity scaling group into analysis of MPMS index for laboratory characterization of wettability of reservoir rocks

Incorporation of viscosity scaling group into analysis of MPMS index for laboratory characterization of wettability of reservoir rocks

Fundamentals of Reservoir Surface Energy as Related to Surface Properties, Wettability, Capillary Action and Oil Recovery from Fractured Reservoirs by Spontaneous Imbibition

Asymmetry Characteristics of Oil Production by Spontaneous Imbibition from Cores with Two Ends Open

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