Article pubs.acs.org/EF
Liquid Intake of Organic Shales H. Dehghanpour,* H. A. Zubair, A. Chhabra, and A. Ullah Department of Civil and Environmental Engineering, School of Mining and Petroleum Engineering, University of Alberta, Edmonton, Alberta T6G 2W2, Canada ABSTRACT: Organic shales are exposed to treatment fluids during and after hydraulic fracturing operations. The fluid−shale interaction influences the petrophysical alteration of the fractured shale and the fate of the fracturing fluid. We systematically measured the spontaneous water and oil intake of five shale samples collected from the cores of two wells drilled in the Horn River basin. The samples represent three shale formations with different mineralogy and petrophysical properties. We characterize the samples by measuring the porosity, conducting X-ray diffraction, and interpreting the well logging data and scanning electron microscopy images. The water intake is higher than the oil intake for all samples. The excess water intake and the physical alteration degree correlate with the shale mineralogy and petrophysical properties. The ratio between the water and oil intake is much higher than the ratio between the water and oil capillary pressures, even for the non-swelling shales. The comparative study indicates that the water intake of organic shales is controlled by both adsorption and capillarity.
1. INTRODUCTION Recent advances in horizontal drilling and multi-stage hydraulic fracturing have shifted the industry focus toward hydrocarbon recovery from organic shales. The shale reservoir is in contact with the fracturing fluid through the extensive surface area created after the fracturing operation. Furthermore, special treatment fluids, such as surfactant solutions, can be used to enhance oil recovery from the shale reservoirs. Optimizing the formulation of fracturing and enhanced recovery fluids requires understanding and modeling of the fluid−shale interaction. This interaction may include clay swelling, mineral dissolution, water adsorption, and counter-current imbibition. Clay swelling and water adsorption of reactive shales result in wellbore instability, which has been studied extensively in the drilling engineering context.1−3 Swelling of reactive shales depends upon the type and concentration of the ions in the aqueous phase and the type and concentration of the clay minerals in the shale.4,5 However, liquid intake of organic shales needs further investigation in the context of reservoir engineering. Spontaneous imbibition of the aqueous phase in fractured sandstone and carbonate reservoirs has been studied as a possible mechanism for enhanced oil recovery.6 Extensive experimental and mathematical investigations have been conduced for relating the imbibition rate and total oil recovery to the capillary and gravity forces and the geometrical parameters.7−9 The spontaneous imbibition in low-permeability rocks has also been studied experimentally and theoretically.10,11 However, understanding and modeling the liquid imbibition in organic shale reservoirs require experimental data on downhole shales. In general, the fluid interaction with shales is more complicated than that with other types of rocks. In addition to capillary forces, the organic material and reactive clay minerals can influence the liquid flow in the small pores of shales. Wang et al.12 measured the counter-current imbibition of oil and water in some outcrop shales. In some tests, they observed significant swelling and induced fractures, which © 2012 American Chemical Society
increased the shale permeability. Furthermore, various surfactant formulations have also been tested for hydrocarbon extraction from organic shales.13 The gas transport in low-permeability shales has been welldetailed recently.14−17 However, the liquid transport in gas and oil shales, which is critical for designing the fracturing and treatment fluids18 needs further investigation.18−21 This paper aims at comparing the oil and water intake of various shales to distinguish between the adsorption and capillary forces responsible for the liquid intake. This paper also aims at relating the imbibition mass to the shale properties measured in the lab and downhole by the logging tools. We select five shale samples with different properties from the cores of two wells drilled in the Horn River basin.22,23 We measure the spontaneous imbibition of oil and water in the selected samples and observe a significant difference in the imbibition mass. This difference is correlated to the mineralogy and petrophysical properties of the samples. We demonstrate this correlation by plotting the imbibition mass versus the mineral concentration measured by X-ray diffraction (XRD) and the petrophysical parameters measured by the logging tools.
2. RESULTS We characterize the selected samples and conduct spontaneous imbibition tests. The sample characterization includes measuring the porosity, mineral concentration, and bulk volume and interpreting the well log data and scanning electron microscopy (SEM) images. The dried samples are placed in the imbibition cell, and the weight change is measured. 2.1. Shale Samples. We select three samples (FS, M1, and M2) from the cores of the first well, which include Fort Simpson and Muskwa formations, and two samples (OP1 and OP2) from the cores of the second well, which include Otter Park formation. The reproduced logs of the first and second Received: May 9, 2012 Revised: August 13, 2012 Published: August 20, 2012 5750
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Figure 1. Properties of Fort Simpson and Muskwa formations measured by the logging tools and the approximate location of the samples selected for the imbibition test. (a) Gamma ray log. (b) Neutron porosity and density porosity logs.
Figure 2. Properties of Otter Park formation measured by the logging tools and the approximate location of the samples selected for the imbibition test. (a) Gamma ray log. (b) Neutron porosity and density porosity logs.
porosity observed in Figure 2. The detailed formation properties have been presented elsewhere.22 Table 1 summaries the porosity and other properties of the five samples measured by the logging tools. The natural γ radiation, GR, of the five samples is relatively high, which indicates the presence of clay minerals composed of the radioactive elements. However, the average GR response of Fort Simpson formation with a higher clay concentration is lower than that of Muskwa and Otter Park formations. This indicates the presence of organic material with a possibly high
wells are shown in Figures 1 and 2, respectively. The top formation (Fort Simpson) is a non-organic shale that is indicated by the large separation between the neutron porosity and density porosity observed in Figure 1. The middle formation (Muskwa) is a gas-saturated organic shale that is indicated by the increasing trend of density porosity and the decreasing trend of neutron porosity observed in Figure 1. The bottom formation (Otter Park) is a gas-saturated organic shale that is indicated by the overlap of density porosity and neutron 5751
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Table 1. Properties of the Five Samples Selected for the Imbibition Experimentsa label
depth (m)
GR (API)
ϕN
ϕD
ϕcore
R (Ω m)
PEF
TOC (wt %)
formation
FS M1 M2 OP1 OP2
1755 1771 1792 2632 2640
138 188 243 131 162
0.3 0.25 0.152 0.108 0.135
−0.015 0.06 0.152 0.074 0.148
0.06 0.05 0.21 0.15 0.07
3.9 7 15 60 35
4 4 3 4.1 3.9
2 2.4 3.7 NA NA
Fort Simpson Muskwa Muskwa Otter Park Otter Park
a
The density porosity (ϕD) and neutron porosity (ϕN) of samples OP1 and OP2 are determined in limestone units and those of samples FS, M1, and M2 are determined in sandstone units. GR, R, and PEF represent natural γ radiation, resistivity, and photoelectric factor of the rock measured by the downhole logging tools. The percentage of total organic carbon (TOC) is estimated from the GR values.22,25 The core porosity (ϕcore) is determined by eq 1.
Table 2. Mineral Concentration (wt %) of the Five Shale Samples Determined by XRD label FS M1 M2 OP1 OP2
calcite 0.5 ± 0 0.9 ± 4.4 ± 12.9 ±
0.4 0.5 0.2 0.4
quartz 29 36.7 45 60.8 43.6
± ± ± ± ±
1.3 1.2 1.7 1.2 1.1
dolomite
chlorite IIb2
± ± ± ± ±
6.5 ± 0.8 4.4 ± 0.4 0 0 0
2.7 5.2 1.9 2.6 2.2
0.3 0.4 0.3 0.2 0.5
illite 1Mt 55.4 48.3 43.0 25.7 33.8
± ± ± ± ±
1.7 1.5 1.7 1.3 1.2
plagioclase albite 4.1 3.6 5.2 3.7 4.4
± ± ± ± ±
0.5 0.5 0.5 0.4 0.4
pyrite
matrix density
± ± ± ± ±
2.747 2.744 2.79 2.748 2.772
1.7 1.7 4.0 2.8 3.2
0.2 0.2 0.2 0.1 0.2
Figure 3. Comparison between the porosity of the five shale samples determined by the different methods.
uranium concentration in Muskwa and Otter Park formations.24 The neutron porosity, ϕN, of sample FS is much higher than its density porosity, ϕD, which is a typical response in water-saturated shales. ϕN and ϕD values of samples M2, OP1, and OP2 are relatively close together. This indicates the simultaneous presence of gas and clay minerals. The resistivity, R, of sample FS is relatively lower than that of other samples, which is expected because the presence of hydrocarbon increases the R. 2.2. XRD. Table 2 presents the concentration of the different minerals composing the matrix of the five shale samples, which is determined by the XRD technique. The dominant clay mineral is illite, and the dominant non-clay mineral is quartz. In general, with the increase of the depth, the quartz concentration increases and the illite concentration decreases. Sample FS has the maximum illite concentration and the minimum quartz concentration. The calcite concentration in samples FS, M1, and M2 is negligible, while its concentration in samples OP1 and OP2 is noticeable. 2.3. Porosity Measurement. The density and neutron porosity values of Figure 1 are determined in freshwater-filled sandstone units, and those of Figure 2 are determined in freshwater-filled limestone units. Therefore, determining the true in situ porosity requires the true in situ fluid density (i.e., formation water and gas) and the true rock matrix density. In
general, the neutron log overestimates the shale porosity because of the presence of hydroxyl groups in the clay minerals, and the density log underestimates the porosity when gas is present in the rock pore space.24 Figure 1 shows that, by moving from a non-organic shale toward a gas-saturated organic shale, the separation between the neutron and density porosity logs decreases. The two logs completely overlap in Otter Park formation, as shown in Figure 2. We measure the porosity of the samples using a helium porosimeter and also a simple weight balance technique. Figure 3 compares the porosity of the samples detemined by the different methods. Figure 3a compares the values measured by the porosimeter with the values determined by the density porosity log. ϕD is very sensitive to the matrix density used in the density porosity equation.24 Therefore, we use the XRD results presented in Table 2 to correct ϕD for the matrix density. Figure 3b shows that the lithology correction increases the ϕD values. We found that the size of crushed shale samples should be small enough to obtain meaningful porosity values by the helium porosimeter. This can be explained by pore accessibility, which can also result in the dependence of mercury injection capillary pressure (MICP) profiles on the sample size.26 In the next step, we use the matrix density determined by XRD to determine the sample porosity by a simple weight balance equation. 5752
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conventional SEM images of the five samples. If we interpret the dark spots to be the void space, pores in the order of 100 nm are visible in all of the samples. However, the microstructure of the samples can be more visible using ion-milling and backscattered SEM imaging.29,31 The plate-like clay minerals and quartz crystals are visible in the images of Figure 4, but the detailed image analysis for mineral characterization is beyond the scope of this paper. 2.5. Surface Properties. Kerosene and water are used as the oleic and aqueous phases, respectively. Table 3 presents the concentration of the minerals in the water phase used for the imbibition experiments. We measure the equilibrium contact angle to compare the shale/oil and shale/water interface properties. Figure 5 compares the water and oil droplets on the clean surfaces of the five shale samples. Oil completely wets all of the samples, which is quantified by a zero contact angle. Water partially wets all of the samples. The approximate water contact angles, measured at room temperature and atmospheric pressure, are listed in Table 4. The water contact angle increases by increasing the depth, which can be explained by the increase of the organic material concentration. Table 4 also lists the ratio between the water and oil capillary pressures based on the Young Laplace equation. This ratio decreases from 2.14 for sample FS to 1.54 for sample OP2. 2.6. Imbibition Results. The samples are heated in the oven at 105 °C for 24 h to ensure moisture evaporation. The dried samples are weighed and then placed in the imbibition cells filled with water or oil. After 72 h, the samples are removed from the imbibition cell and weighed to determine the amount of water or oil intake. 2.6.1. Visual Data. In this section, we present the images taken during and after the imbibition experiments. The samples described in Table 1 are divided into two almost identical parts, dried, and placed in the imbibition cells filled with water or oil. We observed significant air bubbles during the water imbibition, as shown in Figure 6 for samples M2 and OP1. Because all of the samples are initially dry, the observed air bubbles indicate the counter-current air release as a result of the spontaneous water intake. We hardly observed air bubbles during the oil imbibition in the shale samples. However, the weight balance indicates a noticeable oil imbibition, which will be discussed later. The pictures of the samples after the imbibition tests demonstrate the different degrees of the physical alteration. Figure 7 shows that samples FS, M1, and M2 are fractured and broken into pieces by water. However, the alteration of sample FS, which is a non-organic shale, is more significant than that of samples M1 and M2, which are organic shales. Interestingly, Figure 8 shows that water does not destroy samples OP1 and OP2, which are organic shales. Furthermore, oil does not destroy any of the samples. 2.6.2. Measurements. This section compares the quantitative imbibition results. Table 5 summaries the test results,
mma ρma
vb
(1)
Here, vb is the bulk volume of the shale sample. mma and ρma are the total mass and matrix density of the shale sample, respectively. Figure 3c shows a relative agreement between the corrected density porosity and the lab porosity determined by eq 1. We use the porosity values determined by eq 1 to normalize the liquid volume imbibed in each shale sample. However, this is not the effective shale porosity because it also includes the disconnected pores. 2.4. Pore Size. Determining the size of small pores of shales by the conventional methods, such as mercury injection, has some limitations because of pore accessibility and conformance.26−28 Various imaging techniques have been recently used for visualizing the distribution of minerals, organic material, and pores at the sub-micrometer scale.29,30 Figure 4 shows the
Figure 4. SEM images of samples FS, M1, M2, OP1, and OP2 from panels a to e, respectively. All of the images have been magnified 50 000 times, except panel a that has been magnified 30 000 times.
Table 3. Concentration of the Minerals Present in the Water Phase Used for the Imbibition Testsa
a
component
alkalinity
chloride
hardness
potassium
sodium
sulfate
total dissolved solids
unit concentration
mg/L CaCO3 118
mg/L 3.9
mg/L CaCO3 169
mg/L 0.8
mg/L 9.6
mg/L 65
mg/L 216
The water was not deaerated. 5753
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Figure 5. Pictures of water and oil droplets equilibrated on the surface of the five shale samples. The first and second columns show the water and oil droplets, respectively. The five rows relate to samples FS, M1, M2, OP1, and OP2 from the top to the bottom.
observe a different variation in the oil and water intake of samples OP1 and OP2 from the second well. Water intake of sample OP2 is considerably higher than that of sample OP1, while oil intake of sample OP2 is considerably lower than that of sample OP1. Furthermore, Table 2 shows that the illite concentration of sample OP2 is higher than that of sample OP1. Although sample OP2 does not swell, it appears that its additional clay content results in the excess water intake. Figure 9b presents the volume of oil and water imbibed in each sample divided by the initial sample pore volume. Interestingly, the volume of water imbibed in samples FS and M1 is more than 100% of the initial sample pore volume. This indicates the sample expansion as a result of the internal stresses induced by water adsorption. The data of panels a and b of Figure 9 are correlated, except for sample OP2, which shows a high pore volume of oil intake and a low weight percent of oil intake. This may be explained by the underestimation of sample OP2 porosity. 2.6.3. Correlations. The sample properties including the mineralogy measured by the XRD technique and the parameters measured by the logging tools are different. In the
Table 4. Approximate Values of Water and Oil Contact Angles (θw and θo) and the Ratio between Water and Oil Capillary Pressures Based on the Young Laplace Equationa parameter
FS
M1
M2
OP1
OP2
θw (deg) θo (deg) (σwa cos(θw))/(σoa cos(θo))
27 0 2.14
38 0 1.89
45 0 1.70
46 0 1.67
50 0 1.54
The water and kerosene surface tensions (σwa and σoa) are assumed to be 72 and 30 dyn/cm, respectively.
a
including the sample physical properties and the imbibed mass and volume. Panels a and b of Figure 9 compare oil and water intake of the samples in percent of the dry sample mass and in percent of the dry sample pore volume, respectively. In panels a and b of Figure 9, the samples are ordered in increasing depth. Figure 9a shows that the water mass gained by all samples is significantly higher than the oil mass. The data of samples FS, M1, and M2 from the first well show that oil and water intake decreases similarly by increasing the depth. However, we 5754
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Figure 6. Pictures of samples M2 and OP1 during the imbibition test. (a) Air bubbles are observed during water imbibition in sample M2. (b) Air bubbles are not observed during oil imbibition in sample M2. (c) Air bubbles are observed during water imbibition in sample OP1. (d) Air bubbles are not observed during oil imbibition in sample OP1.
Figure 7. Pictures of samples FS, M1, and M2 after the water imbibition test. (a) Sample FS, which is a non-organic shale, is completely destroyed by water. (b) Sample M1, which is an organic shale, is partly destroyed by water. (c) Sample M2, which is an organic shale, is partly destroyed by water.
Figure 8. Pictures of samples (a) OP1 and (b) OP2 after the water imbibition test show no physical alteration.
concentrations. We observe that the water intake is strongly correlated to the illite and quartz concentrations. In general, increasing the illite concentration increases the imbibed mass,
next step, we investigate the correlation between the imbibed mass and the shale properties. Figure 10 plots the liquid intake in percent of the dry sample mass versus the quartz and illite 5755
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Table 5. Results of Spontaneous Imbibition Tests Conducted on the Five Shale Samples by Using Water (w) and Oil (o) label
FS
FS
M1
M1
M2
M2
OP1
OP1
OP2
OP2
imbibant total area (cm2) bulk volume (cm3) dry weight (g) porosity pore volume (cm3) imbibition mass (% of dry sample mass) imbibition volume (% of dry sample pore volume)
w 51.50 92.7 258.1 0.06 5.5 4.58 212.5
o 61.69 104.9 279.1 0.06 6.5 0.56 31.3
w 54.33 114.1 346.6 0.05 5.6 1.9 115.0
o 61.88 145.4 339.9 0.05 71.1 0.29 31.3
w 59.68 161.2 415.4 0.21 33.7 1.4 18.6
o 59.49 154.7 377.6 0.21 32.3 0.18 2.8
w 56.54 203.5 572.3 0.15 31.1 0.51 9.6
o 56.29 185.8 541.0 0.15 28.4 0.22 5.2
w 73.38 171.7 431.5 0.07 12.2 1.44 51.7
o 72.15 168.7 432.7 0.07 12.0 0.14 6.76
Figure 9. Comparison between the normalized amount of oil and water spontaneously imbibed in the different samples. (a) Imbibed mass divided by the dry sample mass. (b) Imbibed volume divided by the dry sample pore volume.
Figure 10. Normalized mass of water and oil gained by the five samples versus (a) illite concentration and (b) quartz concentration.
Figure 11. Total liquid intake of the samples selected from the first well (Fort Simpson and Muskwa formations) versus (a) GR, (b) ϕN − ϕD, and (c) R measured by the logging tools.
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that the adsorption forces in addition to capillary forces significantly contribute to the water intake of all samples. If we assume that the oil intake is only controlled by capillarity (σoa cos(θo)/r), the capillary-driven water intake should be roughly (σwa cos(θw))/(σoa cos(θo)) times the total oil intake. However, these ratios, which are given in Table 4 for the five samples, are much lower than the corresponding measured ratios presented in Figure 9, even for the non-swelling samples. Therefore, we conclude that a complete model for predicting water intake of organic shales should include both adsorption and capillarity simultaneously, which remains the subject of future research. Result 4 is important for qualitative and quantitative prediction of the shale−fluid interaction using the parameters measured in situ by the logging tools. Muskwa formation, which is a gas-saturated organic shale, is overlaid by Fort Simpson formation, which is a non-organic shale. The petrophysical parameters measured by the logging tools continuously change by increasing the depth from Muskwa to Fort Simpson. We find that increasing the GR and R and decreasing the separation between the neutron and density porosity (ϕN − ϕD) indicate the change from a non-organic shale to a gas-saturated organic shale. We also demonstrate that the liquid intake of the shales is correlated to these indicators.
and increasing the quartz concentration decreases the imbibed mass. However, the total concentration of quartz and illite almost remains constant by increasing the depth according to Table 2. In Figure 11, we plot the normalized oil and water mass imbibed in samples FS, M1, and M2 (from the first well) versus GR, ϕN − ϕD, and R measured by the logging tools. By moving from a non-organic shale (Fort Simpson formation) toward an organic shale (Muskwa), GR and R increase and ϕN − ϕD decreases. Figure 11 shows that, with increasing R and GR and decreasing ϕN − ϕD, the water and oil intake of the samples decreases.
3. DISCUSSION AND SUMMARY We systematically measured the spontaneous water and oil intake of different shale samples, which lead to the following results: (1) Water intake of the dry shales results in the spontaneous release of air bubbles. (2) Water alters some of the samples, and the alteration degree depends upon the sample properties. (3) All of the shale samples studied here show more water imbibition than oil imbibition. (4) The water and oil mass gained by the shale samples is correlated to quartz and illite concentrations and the parameters (GR, R, and ϕN − ϕD) measured by the logging tools. Result 1 indicates the counter-current flow of air during the spontaneous water intake. One may conclude that spontaneous intake of the aqueous fracturing or treatment fluids by the shale matrix can result in counter-current flow of the hydrocarbon from the matrix into the fracture. This result can explain why some fractured gas shales, with a lower fracturing water recovery, exhibit a higher gas production rate.32 However, the water intake of the matrix can also result in capillary blockage and effective permeability reduction during the hydrocarbon production. Result 2 indicates the water adsorption and clay swelling in some of the shale samples. The samples with high clay concentration gain a significant water mass and are eventually fractured and broken into small pieces. Water adsorption by the clay platelets develops internal stresses, which expand the sample. Because the samples are not confined, this expansion can break the samples. The observed alteration is surprising because the dominant clay mineral in all samples is illite. However, this is not a new observation. Similarly, Chenvert1 observed that water adsorption significantly altered illitic shales, even those containing no montmorrilonite. It is possible that minor amounts of water-sensitive mixed-layer clays (illite/ smectite) are present in the altered samples. The presence of mixed layers can be tested by XRD analysis of glycolated samples, which was beyond the scope of this work. Furthermore, the alteration degree of the samples studied here is different. For example, the alteration of Muskwa samples is less significant than that of Fort Simpson samples. Interestingly, water intake does not alter the organic shales of Otter Park formation. However, the ratio between the water and oil intake of the Otter Park samples is much higher than the ratio between the water and oil capillary pressures. This indicates that, even for non-swelling shales, the adsorption forces can contribute to the water intake. Result 3 indicates that the shale samples should be categorized as the water-wet media, which is contradictory to the measured contact angles. A similar study33 showed that Barnett, Eagle Ford, and Floyd shale samples imbibed significantly more water than oil. Furthermore, result 2 shows
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AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected]. Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS The authors thank Dr. Ergun Kuru for useful discussions, Zhe Qi and Hao Fei for assistance in experiments. The authors are grateful to Dr. Dipo Omotoso for analyzing the XRD data and the British Columbia Oil and Gas Commission for providing the core samples.
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REFERENCES
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