Fundamental Study of Imbibition in Fissured Oil Fields

Iffly, R.; Rousselet, D.C.; Vermeulen, Jacqueline L.M.

doi:10.2523/4102-ms

Cited by 13 publications

(16 citation statements)

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“…1, provided that the viscosity ratio is constant. 20,21 Recent studies 12 have shown that, for water/oil systems, the imbibition rate is proportional to the geometric mean of the water and oil viscosities, m g + m w m o Ǹ . To account for the effect of viscosity ratio, sample shape, and boundary conditions, the following modified scaling group was proposed, 12 In the present work, the applicability of Eq.…”

Section: The Scaling Equationmentioning

confidence: 99%

Experimental Verification of a Modified Scaling Group for Spontaneous Imbibition

Zhang

Morrow

Ma³

1996

SPE Reservoir Engineering

275

206

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Spontaneous imbibition is of critical importance to oil recovery from fractured reservoirs. A widely used approach to predict oil recovery involves scale-up of laboratory results to reservoir conditions. Scaling involves the effects of sample size, shape, boundary conditions, viscosity and viscosity ratios, interfacial tension (IFT), pore structure, wettability, capillary pressure, and relative permeability. This work addresses the application of a characteristic length to scaling the combined effects of sample shape and boundary conditions with only minor variations in other parameters except for liquid/liquid (L/L) viscosity ratios.Imbibition measurements are presented for cylindrical Berea sandstone cores of different lengths. For some experiments, core surfaces were partially sealed with epoxy to give different boundary conditions. Cores were initially saturated with refined mineral oils of different viscosities. A synthetic reservoir brine was used as the wetting phase. The characteristic length is defined as a function of bulk volume, areas of surfaces open to imbibition, and the distances from these surfaces to their respective no-flow boundaries. The characteristic length, in combination with a term that compensates for the effect of L/L viscosity ratio, gave close correlation of all data.

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Section: The Scaling Equationmentioning

confidence: 99%

Experimental Verification of a Modified Scaling Group for Spontaneous Imbibition

Zhang

Morrow

Ma³

1996

SPE Reservoir Engineering

275

206

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“…The reservoir rock is chalk, and the productive zones are confined to the Ekofisk and Tor Formations, which are Danian and Maastrichtian in age, respectively. The field was discovered in 1969 and initial production began in 6 1971. The es~imated original oil in place is 0,8·10 stock tank m and the projected primary recovery is about 18 percent.…”

Section: Introductionmentioning

confidence: 99%

“…They discussed the experimental simulation of the imbibition phen%menon and verified the scaling laws of Rapoport. 6 Iffly et.al. investigated the effect of composition of the rock and fluids on the water imbibition.…”

Section: Introductionmentioning

confidence: 99%

An Experimental Study of Water Imbibition in Chalk from the Ekofisk Field

Torsæter

1984

SPE Enhanced Oil Recovery Symposium

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Member SPE-AIME Abstract The Ekofisk Field in the North Sea produces from two lithologically similar, low permeability fractured chalk formations. The Ekofisk Formation of Danian age is separated from the lower Tor Formation of Maastrichtian age by a tight zone of about 15 m thickness. With a projected primary recovery factor of only 18%, the secondary recovery target is substantial. A pilot waterflood has been conducted in the Tor Formation and expansion of waterflooding to a large area of the Tor is planned. For waterflooding to recover substantial oil in a highly fractured rock large saturation changes in the matrix rock must be achieved through water imbibition. Water imbibition in Tor samples is high and variable and the imbibition in Ekofisk samples is low and also variable. The first objective of the laboratory investigation reported here was to establish correlations between imbibition and rock parameters in the highly water wet Tor samples. The second objective was to determine the reasons for differences in Ekofisk and Tor water imbibition. The volume of water imbibed and the initial water saturation in Tor samples correlated very well with porosity for the two wells examined. The water porosity for the two wells examined. The water saturation after imbibition was constant at about 60 percent of pore volume, independent of porosity. percent of pore volume, independent of porosity. Imbibition in the Ekofisk samples from the one well examined varied widely and did not correlate with any of the rock parameters examined. Pore structure studies and extraction experiments with strong solvents indicate that the difference between Tor and Ekofisk samples is due to rock surface chemistry differences. The correlation developed here with the Tor samples provides a sound basis for comparing data from provides a sound basis for comparing data from different wells, for examining the effect of various handling and laboratory procedures, and for data input in models. The indication of rock surface chemistry differences provides direction for further research aimed at explaining in greater detail differences between the Ekofisk and Tor rocks with respect to imbibition. Introduction The Ekofisk Field is located near the center of the North Sea on a relatively simple anticlinal feature (Figure 1). The reservoir rock is chalk, and the productive zones are confined to the Ekofisk and Tor productive zones are confined to the Ekofisk and Tor Formations, which are Danian and Maastrichtian in age, respectively. The field was discovered in 1969 and initial production began in 6 1971 The estimated original oil in place is 0,8 10 stock tank m and the projected primary recovery is about 18 percent. About two thirds of the original oil in place is in the Ekofisk Formation and one third in the Tor Formation. The chalk sediments in the Ekofisk area have rather unique characteristics. The main constituent in this rock is skeletons of coccolithophores, which are unicellular algae. Usually the whole skeleton, the coccosphere is disaggregated into the distinctive coccoliths and further disaggregation produces the plate shaped crystals termed coccolith platelets. plate shaped crystals termed coccolith platelets. Geological studies have shown that the rates of sedimentation are significantly different for the Ekofisk and Tor Formation. The Danian age was dominated by moderately organic productivity and high carbonate dissolution rate, while the Mastrichtian age had high organic productivity and low carbonate dissolution rate. P. 93

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“…Research results are also available from laboratory investigations and related numerical simulations of fractured systems on a single matrix block (Blair 1964;Iffly et al 1972;Kleppe and Morse 1974). Yamamoto et al (1971) developed the earliest compositional model for studying recovery mechanisms from single matrix blocks surrounded by different fluids.…”

Section: Literature Reviewmentioning

confidence: 99%

A Critical Review for Proper Use of Water/Oil/Gas Transfer Functions in Dual-Porosity Naturally Fractured Reservoirs: Part II

Kobaisi

Kazemi

Ramírez

et al. 2009

SPE Reservoir Evaluation &Amp; Engineering

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This paper continues the work presented in Ramirez et al. (2009). In Part I, we discussed the viability of the use of simple transfer functions to accurately account for fluid exchange as the result of capillary, gravity, and diffusion mass transfer for immiscible flow between fracture and matrix in dual-porosity numerical models.Here, we show additional information on several relevant topics, which include (1) flow of a low-concentration water-soluble surfactant in the fracture and the extent to which the surfactant is transported into the matrix; (2) an adjustment to the transfer function to account for the early slow mass transfer into the matrix before the invading fluid establishes full connectivity with the matrix; and (3) an analytical approximation to the differential equation of mass transfer from the fracture to the matrix and a method of solution to predict oil-drainage performance.Numerical experiments were performed involving singleporosity, fine-grid simulation of immiscible oil recovery from a typical matrix block by water, gas, or surfactant-augmented water in an adjacent fracture. Results emphasize the viability of the transfer-function formulations and their accuracy in quantifying the interaction of capillary and gravity forces to produce oil depending on the wettability of the matrix. For miscible flow, the fracture/matrix mass transfer is less complicated because the interfacial tension (IFT) between solvent and oil is zero; nevertheless, the gravity contrast between solvent in the fracture and oil in the matrix creates convective mass transfer and drainage of the oil.

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Fundamental Study of Imbibition in Fissured Oil Fields

Cited by 13 publications

References 0 publications

Experimental Verification of a Modified Scaling Group for Spontaneous Imbibition

Experimental Verification of a Modified Scaling Group for Spontaneous Imbibition

An Experimental Study of Water Imbibition in Chalk from the Ekofisk Field

A Critical Review for Proper Use of Water/Oil/Gas Transfer Functions in Dual-Porosity Naturally Fractured Reservoirs: Part II

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