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Sep 27, 2013 - Determination of Residual Oil Distribution during Waterflooding in. Tight Oil Formations with NMR Relaxometry Measurements. Ping Yang,...
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Determination of Residual Oil Distribution during Waterflooding in Tight Oil Formations with NMR Relaxometry Measurements Ping Yang,† Hekun Guo,‡ and Daoyong Yang*,† †

Petroleum Systems Engineering, Faculty of Engineering and Applied Science, University of Regina, Regina, Saskatchewan S4S 0A2, Canada ‡ Institute of Porous Flow and Fluid Mechanics, Langfang, Hebei 065007, China ABSTRACT: The NMR relaxometry measurements have been designed and applied to quantitatively determine residual oil distribution during waterflooding in tight oil formations. A tight core sample is first saturated with water to measure its NMR transverse relaxation time (T2) spectrum. NMR T2 spectrum is then measured for the core sample after it has been displaced with the fluorinated oil. Subsequently, the core sample is displaced with water until residual oil saturation is achieved, and the NMR T2 spectrum is measured again at the end of the displacement. Subsequently, the constant-rate mercury injection method is used to experimentally measure the size of the pore and throat in the core sample. The residual oil saturation is determined as a function of pore size by comparing the difference between the first and last NMR T2 spectrum. It is found from four core samples with permeability of 0.04−1.70 mD that the average pore size is in a range of 129−145 μm, and the pore throat has a radius of 0.17− 0.89 μm. The original oil saturation is found to be 76−83%, whereas the oil recovery factor is 36−62%; 4−27% of the original oil is distributed in pores larger than 100 μm, 50−54% in pores from 10 to 100 μm, and 21−46% in pores and throats smaller than 10 μm. Residual oil saturation is 1−2% in pores larger than 100 μm, 29−64% in pores from 10 to 100 μm, and 34−69% in pores and throats smaller than 10 μm.

1. INTRODUCTION With the rising global demands on energy and depleting conventional reservoirs, unconventional tight oil resources are increasingly important, and how to exploit them to the maximum potential becomes a focus.1,2 Tight formations have the main characteristics of small grains and fine throats so that non-Darcy flow behavior may elevate the difficulty of field development.3,4 As for such tight formations, the primary recovery factor remains very low (around 5−10% of the original oil in place) even after long horizontal wells have been drilled and massively fractured.5 Numerous attempts have been made to implement waterflooding in the tight formations, with few successes due to both the low permeability and the lack of understanding the underlying mechanisms.3,5,6 It is of practical and fundamental importance to determine the residual oil saturation together with the underlying mechanisms so as to maximize the ultimate oil recovery from the tight formations. Traditionally, microscopic and macroscopic experiments have been employed to identify waterflooding mechanisms in porous media. For the microscopic experiments, monitoring in situ saturation during a coreflood was carried out to evaluate the waterflooded performance with an X-ray CT scanner.7 Thin sections were used to qualitatively visualize and determine the distribution of oil and water in pores and throats.8 For the macroscopic experiments, the cyclic injection process was applied to experimentally improve and evaluate waterflooding performance in a carbonate reservoir.6 In the experiments, the critical and optimum injection rates were experimentally determined during a waterflooding process.9 In addition, water injection tests were conducted at different pressure gradients to examine the effect of gravity on oil recovery.10 However, distribution of residual oil and water saturation in © 2013 American Chemical Society

porous media cannot be determined quantitatively from either of these experiments. Loren and Robinson first proposed a theory relating the NMR relaxation time of water in porous media to the pore size distribution.11 Subsequently, numerous efforts have been made to quantify a linear relation between the transverse relaxation time (T2) and pore size, assuming that the pores can be simplified to columnar or spherical tubes.12−15 During its practical implementation, there exists a large discrepancy between the distribution of pores and throats that was converted from T2 relaxation time and that was obtained from the conventional mercury injection method.16,17 When the complexity of real pores is considered, an exponential relation has also been proposed for such a purpose and with better accuracy.18 Due to the fact that mercury cannot enter into small pores controlled by throats less than 0.12 μm during the experiments, only the right portion of the T2 spectra was used to quantify the distribution of pores and throats.19 Even though the distribution of large pores converted from T2 spectra can match well with that obtained from the mercury injection method, the small pores have not been taken into account. In this paper, the NMR relaxometry measurements have been designed and applied to determine residual oil distribution during waterflooding in tight oil formations. The NMR T2 spectra of four tight oil samples were measured by using the NMR core analysis unit, and the size of pores and throats in the core samples were measured by using the constant-rate mercury Received: April 9, 2013 Revised: September 15, 2013 Published: September 27, 2013 5750

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fluorinated oil, respectively, to the core sample in the core holder at a constant pressure. The 1-D displacement system contains a coreholder (TY-5, Haian, China) and a manual pump (DJB-80A, Haian, China), which is used to supply the confining pressure for the coreholder. The stainless steel core holder is used for coreflooding tests, which is composed of a stainless steel pipe, a sleeve, two distribution plugs, two retainers and two end-caps. Radial confining pressure is applied by the body wall. Independent axial pressure is applied through a floating distribution plug. The distribution plug with an outlet and an inlet allows fluids to be injected through the core sample. After the confining pressure and axial pressure have been released, the retainer and distribution plugs are removed and the end plug is unscrewed. Then, the core sample is easily removed with the sleeve remaining in place in the coreholder. The coreholder has the dimensions 8.0 cm in length and 2.5 cm in diameter. The production system consists of a pressure gauge and a fluid sample collector. Volume of the produced fluids is directly measured by reading the scale on the fluid sample collector, which is exposed under atmospheric pressure. During the experiments, a low-field NMR core analysis unit (RecCore-04, Academia Sinica, China) is used to measure the NMR T2 spectrum, and a constant-rate mercury injection setup (ASPE-730, Coretest Systems, USA) is employed to perform constant-rate mercury injection experiment. As for the NMR core analysis unit, the precession frequency for 1H nuclei is 2.05 MHz, and its average homogeneity in the volume occupied by the core sample is less than 200 ppm. A 10 mL of standard sample including 12 vol % kerosene and 88 vol % carbon tetrachloride is used to measure the signal-to-noise ratio (SNR). The SNR of the measurements is found to be larger than 100 by using a CPMG sequence with an average of 1024 echoes. The pulse length and power used are 20 μs and 300 W, respectively. The accuracy of pulse, pulse frequency, and digital receiver is 250 ns, 0.01 Hz, and 12 bit, respectively. According to the measurements of standard samples, the oil saturation can be obtained by the NMR T2 spectrum with a relative error of less than 10%. As for the constant-rate mercury injection setup, capacity of the pressure sensor is in a range of 0−1000 psi, with an accuracy of 0.05 psi. 2.3. Experimental Procedures. The experimental procedure used in this study is briefly described as follows. First, four tight core samples are dried in oven at 108 °C for 12 h. After that, the length, diameter, and dry weight of the samples are measured. Then, the air permeability of the samples is measured by using the flowmeter method.22 Second, the core samples are saturated with water under a pressure of 12.00 MPa for 12 h. Once completely saturated, their wet weights are measured. The porosity of each core sample is determined by dividing the difference between dry weight and wet weight by its volume. Then, the NMR analysis unit is used to measure NMR T2 spectrum for the four samples, with data stored in a computer automatically. The raw data obtained from NMR measurements are spin−echo trains, which are processed to determine the T2 distributions by using the singular value decomposition inversion algorithm. The waiting time is set to be 3000 ms, echo time 300 μs, echo number 1024, scanning number 64, and gain 50 (i.e., the magnification times of signal is 50). Third, a water-saturated core is placed into the coreholder to be displaced by injecting the fluorinated oil until irreducible

injection method. The fluorinated oil was used to discriminate between water and oil in single and fast one-dimensional (1-D) experiments so that qualitative distribution of residual oil saturation can be obtained by comparing the difference in the NMR T2 spectrum before and after coreflooding experiments for each core sample. Such obtained information is finally combined with a modified linear relation between pore sizes and relaxation times to determine the residual oil distribution as a function of pore size in tight oil formations. This, in turn, helps to understand the mechanisms of waterflooding. The newly developed techniques can also be used for other types of porous media.

2. EXPERIMENTAL SECTION 2.1. Materials. In this study, both fluorinated oil (Sinopec Great Wall Lubricant Oil, China) and synthetic brine are used. In order to differentiate the NMR signal of water from that of oil, D2O and fluorinated oils are the most commonly used substances in the coreflooding experiments.20,21 Compared to D2O, the fluorinated oil is cheap and nonpoisonous, so it is chosen for use in this study. Its density and viscosity are measured to be 1807.0 kg/m3 and 2.24 cP, respectively, at 20 °C and atmospheric pressure. Due to its chemical inertness and excellent thermal and oxidation stability, the fluorinated oil does not interact with either the pore network or synthetic brine; thus, the T2 distribution remains unchanged. Density of the synthetic brine is 1044.0 kg/m3, and its viscosity is 1.02 cP at 20 °C and atmospheric pressure. The composition of synthetic brine is listed in Table 1. Four tight core samples were collected from the Changqing, China, oilfield. The cores are determined to be water-wet, and their physical properties are tabulated in Table 2. Table 1. Composition of Synthetic Brine component

concentration, mg/L

chloride potassium sodium calcium magnesium

26 953 11 451 8 600 1 987 1 009

Table 2. Physical Properties of Core Samples core sample

length, cm

diameter, cm

porosity, %

permeability, mD

#1 #2 #3 #4

3.12 3.25 3.21 3.19

2.52 2.51 2.51 2.51

10.3 9.0 9.4 15.5

0.04 0.14 0.71 1.70

Alcohol (Siqi Trading Co., Ltd., China) and benzene (Sinopec Guangzhou branch, China) have purities of 99.99% and 99.5%, respectively, which are used to clean the core samples. 2.2. Experimental Setup. As shown in Figure 1, the conventional coreflooding experiment setup is composed of a fluid supply system, a one-dimensional (1-D) displacement system, and a fluid production system. The fluid supply system includes a high pressure syringe pump (500HP, Teledyne ISCO, U. S. A.), one cylinder for containing synthetic brine, and one cylinder for storing the fluorinated oil. The high pressure syringe pump is used to introduce synthetic brine and 5751

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Figure 1. Schematic diagram of the coreflooding experiment setup.

1 1 1 1 = + + T2 T2,bulk T2,surface T2,diffusion

water saturation is attained at a constant pressure of 10.00, 8.00, 3.46, and 1.31 MPa for the four samples, respectively. Then, the NMR T2 spectrum of each of the four oil-saturated core samples is measured by using the NMR analysis unit with the same parameters as before. Because there is no nuclear magnetic signal in the fluorinated oil, the nuclear magnetic signal is originated from the irreducible water in the cores. As such, the general distribution of the original oil saturation in the core can be obtained by comparing the difference of the NMR T2 spectra before and after the coreflooding experiments. Fourth, the flooded core samples are placed back to the coreholder and displaced with water until the residual oil saturation is achieved at a constant pressure of 10.00, 8.06, 3.00, and 1.29 MPa for the four core samples, respectively. Then, the NMR T2 spectrum of the four flooded samples is measured again by using the NMR analysis unit with the same parameters as before. A qualitative distribution of residual oil saturation can be obtained by comparing the difference of the NMR T2 spectra before coreflooding experiments and after waterflooding for each core sample. Fifth, the four core samples are cleaned by using alcohol and benzene and dried in oven at 108 °C for 12 h. Once completely dried, a core slide is chipped out from each of these core samples. Finally, the core slide is placed in the constant-rate mercury injection apparatus to experimentally measure size of the pore and throat. During the experiments, mercury is injected into the core slide at a constant rate of 0.00005 mL/min. During the injection process, the pressure fluctuates periodically, and the experiment is terminated when the pressure reaches 6.20 MPa. All the measured data are collected and stored in the computer automatically. It should be noted that the confining pressure is set to be 2.0 MPa higher than the inlet pressure of the core during all the experiments. All the experiments are conducted at a room temperature of 25.0 ± 1.0 °C. The pressure during the experiments is recorded by a general pressure gauge with an accuracy of 0.10 MPa. 2.4. Determination of Pore and Throat Size. As for the NMR transverse relaxation time, T2, of a fluid in a pore is given by the following equation.11−15

(1)

where T2,bulk is the bulk relaxation time of the pore-filling fluid (ms), T2,surface is the surface relaxation time (ms), and T2,diffusion is the relaxation time as induced by diffusion (ms). As for fluid flow in porous media, T2,bulk is usually neglected because T2,bulk is much larger than T2 in the range of 2000−3000 ms, and T2,diffusion is also neglected when the magnetic field used is deemed to be uniform with a quite small field gradient, and echo time is small enough.23 Then, T2 is mainly dependent on T2,surface, which is associated with specific surface area of a pore. T2,surface can be expressed as follows.19,23 ⎛S⎞ 1 = ρ2 ⎜ ⎟ ⎝ V ⎠ pore T2,surface

(2)

where ρ2 is the surface relaxivity (μm/ms), S is the interstitial surface area (μm2), and V is the pore volume( μm3). S/V can be rewritten as a function of the dimensionless shape factor of a pore, Fs, and pore radius, r (μm) S = Fs/r V

(3)

Combining eqs 2 and 3, we have T2,surface =

1 r ρ2 Fs

(4)

When a given core is considered, its surface relaxivity (ρ2) and shape factor (Fs) can be assumed to be constant. Thus, T2 = Cr

(5)

where C = 1/(ρsFs), and C is a constant conversion coefficient (ms/μm). As for tight core samples, it is experimentally found that the injection mercury saturation cannot attain 100%. For constantrate mercury injection, the experiment is terminated when pressure reaches 6.20 MPa, so mercury can only enter into relatively large pores controlled by the throats larger than 0.12 μm during the experiments.19 Because NMR can be used to quantify very tiny pores and throats,23 only the right portion of the T2 spectrum is used to determine the conversion coefficient 5752

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by comparing the T2 weighted average value of the right part of T2 spectrum with the average pore radius from constant-rate mercury injection.19

the sum of amplitude after coreflooding and waterflooding. Because every core has its own conversion coefficient, it is not proper to compare them with each other. In addition, the quantity distribution of pore fluid for every core cannot be determined; thus, the following analysis is needed. 3.2. Pore and Throat Size Distribution. Table 4 shows the pore and throat size distribution for the four core samples from the constant-rate mercury injection. It can be seen from this table that, for the four core samples, the average pore size is in the range of 129−145 μm, and their throats have a radius of 0.17−0.89 μm. With the increase of permeability, the range of throat sizes together with its average value increases, though the pore size distribution has no obvious relationship with permeability, indicating that it is the throat size that determines the permeability. 3.3. NMR Amplitude Distribution. T 2 transverse relaxation times for the four samples are converted into pore radius using the modified linear relation as mentioned previously. The conversion coefficient is obtained by comparing the T2 weighted average value of the right part of the T2 spectra with the average pore radius (see Table 5). With the conversion coefficients, the measured NMR amplitude distribution as a function of pore size under various conditions for the four core samples are plotted in Figures 3−6. When oil and water flow in porous medium, there exists capillary pressure Pc (Pc = 2σ cos θ/r where r is throat radius, σ is surface tension, and θ is contact angle). During the experiments, oil can displace water only if the driving force overcomes the capillary pressure. Because of the heterogeneity in the porous medium, the oil enters into the relatively large pores and throats first, and later enters the smaller ones. The oil displaces water along the median axis, and the water left on the pore wall will flow along it. As such, the irreducible water mainly consists of a water film on the large pore walls and water column in small pores, which can be used to interpret the phenomena in Figures 3 and 4. However, if the core sample is heavily heterogeneous and large pores are surrounded by a group of small pores, the water in the large pores and small pores will form the irreducible water (see Figures 5 and 6). 3.4. Residual Oil Distribution. Table 6 shows the distributions of original oil, recovered oil, and residual oil for the four core samples. It is found that 4−27% of the original oil is distributed in pores larger than 100 μm, 50−54% in pores from 10 to 100 μm, and 21−46% in pores and throats smaller than 10 μm. Also, the recovered oil of 9−48% comes from pores larger than 100 μm, 41−88% from pores from 10 to 100 μm, and 3−20% from pores and throats smaller than 10 μm. Accordingly, residual oil saturation is determined to be 1−2% in pores larger than 100 μm, 29−64% in pores from 10 to 100 μm, and 34−69% in pores and throats smaller than 10 μm. In these four core samples, residual oil is mainly occupied in pores and throats smaller than 10 μm and the remaining oil is located in pores from 10 to 100 μm. During the experiments, the injected water displaces the crude oil in large pores and throats first because of the relatively small resistance force in large pores and throats, which is also called fingering. When two fingering channels meet each other at some pore locations, the oil between these two channels will form the residual oil. When irreducible water contacts with injection water, crude oil is pushed off from the pore surface. When the displacement velocity is too large, the water would surround the lowpermeability zone. Then, as water slowly imbibes into the surrounding low-permeability zone, the oil is displaced but

3. RESULTS AND DISCUSSION 3.1. NMR T2 Spectra. NMR refers to the response of atomic nuclei to magnetic fields. Hydrogen, abundant in both water and hydrocarbons, has a relatively large magnetic moment and produces a relatively strong signal compared to those of most of the nuclei found in earth formations. To date, almost all NMR rock studies are based on responses of the nucleus of the hydrogen atom.24 Because there is no nuclear magnetic signal in the fluorinated oil used for this experiment, the nuclear magnetic signal is originated from the water in the cores. Original oil saturation in the core can be obtained by comparing the difference of NMR T2 spectrum before and after the coreflooding experiments for each individual core sample. The recovered oil saturation can be obtained by comparing the difference of NMR T2 spectrum after coreflooding and after waterflooding. Residual oil saturation can be obtained by comparing the difference of NMR T2 spectrum before coreflooding experiments and after waterflooding. In the low-field NMR core analysis unit, specified pulse sequences are used to generate a series of the so-called spin echoes, and the amplitude of the spin echoes’ decay as a function of time can be fit very well by a sum of decaying exponentials, each of which has a different decay constant.24 All the decay constants then form a set of the decay spectrum or transverse relaxation time (T2) distribution. T2 distribution under some interval can be obtained by integrating the amplitude of this area with respect to T2 relaxation time. NMR T2 spectrum for core sample #1 is shown in Figure 2, from which it can be observed that original oil and residual oil

Figure 2. Distribution of T2 relaxation time for Core #1 under different conditions.

mainly distribute in the interval of 0.1−100 ms and 1−10 ms, respectively, whereas the recovered oil mainly comes from the interval of 1−100 ms. Table 3 shows NMR T2 distribution for the four core samples under different experimental conditions. The original oil saturation is found to be 76−83%, which is obtained by comparing the sum of amplitude before and after coreflooding experiments. The oil recovery factor is 36−62%, which is obtained by dividing the difference of the sum of amplitude before and after coreflooding with the difference of 5753

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Table 3. NMR T2 Distribution for the Four Core Samples under Various Conditions NMR T2 distribution, % core sample

experimental condition

0.1−10 ms

10−100 ms

100 −1000 ms

original oil saturation, %

recovery factor, %

#1

saturated water saturated oil waterflooding saturated water saturated oil waterflooding saturated water saturated oil waterflooding saturated water saturated oil waterflooding

78 100 64 55 92 45 29 49 23 48 31 17

22 0 36 43 7 53 49 30 42 45 47 71

0 0 0 2 1 2 22 21 35 7 22 12

83

48

82

62

81

54

76

36

#2

#3

#4

Table 4. Pore and Throat Size Distribution of Core Samples pore radius, μm

throat radius, μm

core sample

range

average

range

average

#1 #2 #3 #4

45−240 10−390 25−495 40−455

145 131 133 129

0.12−0.22 0.14−0.58 0.15−1.14 0.23−1.65

0.17 0.39 0.57 0.89

Table 5. Conversion Coefficient for the Four Samples core sample

conversion coefficient, ms/ μm

#1 #2 #3 #4

0.30 0.39 0.96 0.73

Figure 4. Distribution of pore size for Core #2 under different conditions.

Figure 3. Distribution of pore size for Core #1 under different conditions.

cannot form a continuous pathway to flow out. In this way, the oil is entrapped and stays in pores as residual oil. When the displacement velocity is too small, the injected water flows along the pore wall and entraps the oil in pores that forms the residual oil. In general, the core with a higher permeability should have a higher recovery factor. Compared to Core #2 with a permeability of 0.14 mD and recovery of 62%, however, Core #4 with a permeability of 1.70 mD just achieves a recovery factor of 36%. During the experimental process, other

Figure 5. Distribution of pore size for Core #3 under different conditions.

parameters remain almost the same, but the displacement velocities for Cores #2 and #4 are 0.01 mL/min and 0.32 mL/ min, respectively. As such, inappropriate displacement velocity is likely to be the factor that leads to a lower recovery in a larger permeability core. This may be due to the fact that it will be easier for the injected fluids to bypass the residual oil in the porous media. 5754

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original oil is distributed in pores larger than 100 μm, 50−54% in pores from 10 to 100 μm, and 21−46% in pores and throats smaller than 10 μm. Residual oil saturation is found to be 1−2% in pores larger than 100 μm, 29−64% in pores from 10 to 100 μm, and 34−69% in pores and throats smaller than 10 μm. Therefore, the pores that are smaller than 100 μm should be the focus of future studies, especially the pores and throats smaller than 10 μm.

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AUTHOR INFORMATION

Corresponding Author

*D. Yang. Phone: 1-306-337-2660. Fax: 1-306-585-4855. Email: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The authors would like to acknowledge to the Institute of Porous Flow and Fluid Mechanics, Langfang, Hebei, China, for permission to publish the paper and financial support to H.G. from Changqing Oilfield. Also, the authors acknowledge a Discovery Grant awarded to D.Y. from the Natural Sciences and Engineering Research Council (NSERC) of Canada. The authors also sincerely appreciate the valuable comments made by the anonymous reviewers.

Figure 6. Distribution of pore size for Core #4 under different conditions.

Table 6. Distributions of Original Oil, Recovered Oil, and Residual Oil for the Four Core Samples oil saturation distribution, % core sample

oil category

100 μm

#1

original oil recovered oil residual oil original oil recovered oil residual oil original oil recovered oil residual oil original oil recovered oil residual oil

36 20 51 29 14 53 21 11 34 46 3 69

54 60 48 50 52 46 52 41 64 50 88 29

10 20 1 21 34 1 27 48 2 4 9 2

#2

#3

#4

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REFERENCES

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In this study, the capillary end effect cannot be quantified. The T2 spectra measured after displacements, however, are found to be reliable and physically reflect the fluid distribution with the capillary end effect. In general, the capillary end effect can be reduced or eliminated by using a long core plug, a large displacement velocity, or a three-segment core plug.25 Due to the limited dimension of the NMR core analysis unit, long core plugs cannot be used for the measurement. As the cores have a permeability of less than 2 mD, a large displacement velocity cannot be achieved at the experimental pressures. A threesegment core plug will be used to reduce or eliminate the capillary end effect for future experiments when available.

4. CONCLUSIONS The NMR relaxometry measurements have been designed and applied to quantify residual oil distribution during waterflooding in tight oil formations. Through the constant-rate mercury injection method, it is found from four core samples with permeabilities of 0.04−1.70 mD that the average pore size is in a range of 129−145 μm and the pore throat has a radius of 0.17−0.89 μm. By comparing the sum of amplitude before and after coreflooding experiments, the original oil saturation is measured to be 76−83% and the oil recovery factor is 36−62%. By comparing the difference of NMR T2 spectrum before and after the coreflooding experiments, it is found that 4−27% of 5755

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