Bentheimer

R. A. Waggoner, E. Fukushima 1996, (Velocity distribution of slow fluid flows in Bentheimer sandstone an NMRI and propagator study), Magn. Reson. Imag. 14, 1085. 

Fig. 3.6.10 Distributions of diffusivity and relaxation times for partially brine- and oil-saturated Bentheim sandstone [43].

Our method is demonstrated with experiments on a Bentheimer sandstone sample. The sample was prepared to be cylindrically shaped with a diameter of 2.5 cm and a length of 2.0 cm. The sample was fully saturated with de-ionized water under vacuum. We performed the CPMG imaging experiment described in the previous section to measure the magnetization intensity at 50 echoes spaced by 4.6 ms for each of 32 x 16 x 16 voxels within the field of view of 3.0 cm x 3.0 cm x 3.0 cm. The corresponding voxel size is 0.938 mm x 1.88 mm x 1.88 mm. We used 1 s of repetition time (TR) and the total imaging time was 4.3 min. 

Fig. 4.1.2 The estimated normalized T2 relaxation distribution for the selected voxel in the Bentheimer sample.

Fig. 4.1.4 Porosity distribution within a horizontal layer of the Bentheimer sample. Axis z- is parallel with the static magnetic field.

We demonstrate the procedure with an experiment conducted on a Bentheimer sandstone sample. For simplicity, we use a relatively thin sample and resolve only the two in-plane spatial coordinates. The sample is a rectangular parallelepiped shape having a length of 50 mm extending in the z direction, width 25 mm along the z2 direction and thickness 5 mm in the z3 direction. The sample was sealed laterally with epoxy and mounted in Plexiglass end-plates with O-rings and tube... 

Fig. 4.1.7 Superficial average velocity data for the flow experiment with the thin Bentheimer sandstone sample. Each arrow represents the direction and relative magnitude of the superficial average velocity at the corresponding voxel. The velocities are measured for 58 x 20 voxels.

Fig. 4.1.8 Determined permeability distribution for the thin Bentheimer sample. The vertical axis represents the permeability value for the corresponding point.

Two different sandstone samples are used to demonstrate the methodology developed in Sections 2.1-2.3 in one spatial dimension. The first sample is a Bentheimer sandstone sample we have labeled KBE, which is saturated with oil. The second sample is a Brown sandstone sample, labeled MCD, that is saturated with water. 

Fig. 2. One-dimensional CPMG images and the intrinsic magnetization for a Bentheimer sandstone sample (KBE).

Fig. 3. Predicted and observed magnetization of the Bentheimer sandstone sample (voxel 80).

The developed methodology is now used to determine a two-dimensional porosity distribution on a Bentheimer sandstone sample (KBE) saturated with oil. The sample and reference used are the same as those for one-dimensional imaging in Section 2.4.1. A two-dimensional CPMG imaging sequence is applied with field of view of 10.00 cm x 3.50cm, which gives a voxel size of 0.078 cm x 0.11 cm x 0.58 cm. The porosity distribution of the two-dimensional... 

The method to determine fluid velocities is described in Section 3.1. The inverse problem is described in Section 3.2, and demonstrated on data from a Bentheimer sandstone sample in Section 3.3. 

An example of a joint density function gA (r, R) is shown in Fig. 12. The sample is a Bentheimer sandstone in a rectangular parallelepiped shape 50 mm long extending in the -direction, 25 mm wide along the x-direction, and 5 mm thick in the y-direction. The average volumetric flow rate of the water was 1.5 ml min-1 along the -direction. The sample is located between the two spikes resulting from free water present in the end caps of the core holder. 

Fig. 12. The joint spin-velocity density function, p(z)P (v , -), as a function of position z for water flow in the rectangular Bentheimer sandstone sample (voxel size is 0 94 mm)...

Figure 13 shows an example of (zM with respect to each voxel located at (z, x) for a fluid flowing through a Bentheimer sandstone sample, Fig 14. 

Fig. 15. Two-component velocity distribution with the Bentheimer sandstone sample.

Figure 16. Gas-blockage performance of 1.0% Fluowet OTN foams in bead packs of indicated length at screening conditions, and in Bentheimer sandstone at reservoir conditions. Permeability is 1.4—1.8 darcy, temperature is 70 °C, and residual crude oil is present (except, 24-cm pack 8 darcy and 21 °C).

In sandstones, values for Sw closer to connate (0.18 to 0.21 in 1.3-darcy Bentheimer) were obtained with fluorosurfactant foams, although gas blockage was as strong as in bead packs of comparable permeability (21). Because most of the water in such cores is presumed to occur in the smallest pores, which hold no foam (33), it probably means that the actual gas-blocking foam is also of a similar dry nature in the rock. 

Figure 3. Cumulative pore size distribution for Bentheim sandstoney with respect to different methods of measurements (35).

Surfactant slug/polymer drive systems which have proved to be effective in recovering waterdrive residual oil in 30 cm long Bentheim sandstone cores have been found to be much less effective in longer (90 cm) cores. This is attributed to polymer/surfactant phase separation, the phenomenon which has little time to develop in experiments with short cores. 

We have previously described (2) how a surfactant system producing such an optimal microemulsion in situ upon contact with residual oil was able to recover 90% of the waterdrive residual oil from short (30 cm) Bentheim sandstone cores (Figure 1). 

In this paper we report on surfactant floods in longer (0.9-1.5m) Bentheim sandstone cores. The purpose of these experiments has been to investigate the possible occurrence of incompatibilities between the surfactant slug and the polymer drive in cores. 

Fig. 1. Surfactant flooding experiments in Bentheim sandstone cores (30 cm long, T = 62 ). Oil production versus cumulative injection.

Floods through Bentheim Sandstone Cores (62 C, Slug-size 13% pore volume, surfactant (100% a i,) concentration 4%)... 

A more recent study [70] examined the effects of the polymer on surfactant adsorption in a low tension polymer water flood (LTPWF). The surfactant was alkylpropoxyethoxy sulfate, Ci2-i5-(PO)4-(EO)2-0S03 Na, and the polymers were xanthan and a copolymer of acrylamide and sodium 2-acrylamido-2-methylpropane sulfonate (AN 125 from Floerger). The solid materials were sandstone cores from a North Sea oil reservoir, Berea, and Bentheim cores. For these systems the xanthan caused a 20% reduction in the adsorption of the surfactant. It was also observed that surfactant adsorption appeared to increase as the water... 

N. S. Kaveh, E. S. J. Rudolph, R Van Hemert, W. R. Rossen, and K. Wolf, Wettability evaluation of a COj/water/Bentheimer sandstone system Contact angle, dissolution, and bubble size. Energy Fuels, 28,4002-4020 (2014). 

Figure 6.2. Comparisons of (a) flow behaviour indices (n) and (b) flow coefficients (K) in capillary and Bentheim sandstone experiments for xanthan solutions (after Teew and Hesselink, 1980).

TABLE 5.14—PARAMETERS FOR CORE FLOW TESTS IN BENTHEIM SANDSTONES ... 

Q+S Consult, Bad Bentheim, Germany e-mail qs-consult t-online.de... 

FIGURE 2.17 Permeability versus grain size Bentheim sandstone. After Engelhard (I960) and Schopper (1982). 

Besides porosity, the pore size has a dominant influence on permeabihty. Figure 2.17 shows permeability versus grain size for Bentheim sandstone with a strong correlation. Regression results in the equation... 

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