16SPE-175968-MSSPE-175968-MS15

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SPE-175968175968-MSA Study of Mercury Intrusion on Montney Formation Rocks and How It Relates to PermeabilityB. Salimifard, D.W. Ruth, University of Manitoba; B. Nassichuk, Trican Well Services Ltd.Copyright 2015, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE/CSUR Unconventional Resources Conference held in Calgary, Alberta, Canada, 2022 October 2015.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

AbstractThe Montney Formation, a tight unconventional reservoir in Western Canada, has been explored for the past two decades and over the last 10 years has moved towards being a primary exploration target. Qualitative and quantitative petrophysical analysis of the Montney Formation has always been a challenge to researchers. Reservoir characterization is generally hindered by lab-based methods for permeability estimation, proper estimation of the pore size distribution and development of correlations between the rock properties and hydraulic flow.This report examines results from permeametry, mercury porosimetry, helium pycnometry and scanning electron microscopy (SEM) images performed on 53 samples of the Montney Formation to understand the complicated pore network structure of the rock and study the predictive power of a permeability prediction model.Pulse-Decay permeability is measured on cores at effective reservoir pressure. Crushed samples are used to obtain mercury capillary pressure, pore size distribution curves, GRI and mercury porosity and matrix permeability. SEM images are used to study pore development and porosity as well as investigating the presence of microfractures. The permeabilities of these samples range from 10 nanodarcies to 0.1 milidarcies and porosities range from 2-10 percent. Due to high surface intrusions in the mercury porosimetry tests, extraction of pore size distributions and capillary pressure curves are problematic and cut-offs are applied based on the derivative of the capillary pressure curve to help understand the complicated pore network of the rock and correlate it with permeability.This study shows that mercury porosimetry results can be used to categorize the rocks into subcategories for further analysis. Different methods correlating rock properties to permeability are examined. The results specifically indicate that pulse-decay permeability is influenced by over-burden pressure and the presence of microfractures and that the appropriate pore diameter shows consistent correlation with the derivative of the capillary pressure curve.

Introduction:During the past 25 years shale formations have changed their reputation from an unwanted troublesome reservoir feature to one of the larger oil and gas reservoirs. Extensive study has been done on the producibility of shale gas and oil reserves, and with the help of new drilling and production techniques, shale production has spiked up. There are 8 active shale plays in Canada and it is estimated that these reserves contain 1,100 trillion cubic feet of shale gas and over 32 trillion barrels of tight oil. Producing these reserves can have a major effect on the Canadian economy. The Montney formation is one of the largest tight reservoirs in western Canada, extending from north-central Alberta to northeastern British Columbia. It is estimated to have 2,300 trillion cubic feet of gas in place and 136 billion barrels of original oil in place with the Alberta portion being mostly home to the oil reserves and the BC portion mostly home to the gas reserves according to the Unconventional Resources Guidebook (2012, 2013 and 2014).

Sample description and preparationThe Alberta Geological Survey (2010) characterises the Montney formation as fine-grained shoreface sandstones, shelf siltstones and shales, fine-grained turbidites and organic-rich phosphatic shale. The Montney trend also includes the Doig formation that overlies the Montney formation and is composed of agrillacious siltstone and dark calcareous shale.Montney Formation samples were collected from archived core within Northeastern British Columbia. Wells were selected to represent the main exploration corridor of the dry gas Montney zone. Several wells were selected in the deep basin area and off of the Primary Montney fairway. Given the availability of continuous core sections, efforts were made to obtain representative samples within the upper, middle and lower Montney; however, the majority of samples are from the upper Montney.All of the analyzed wells were logged to identify basic lithology, facies and zones of high bioturbation. From the initial logging, intervals were selected to represent zones with broad geological similarities which could be isolated and tested. Full core samples were removed and carefully preserved and transported to the Trican Geological Solutions testing facility in Calgary. Each sample was examined to determine an optimal location for cutting a 25.4 mm (1) diameter core plug. A direct drive core plugging instrument with water as the circulating/cooling fluid was used to cut all plugs. Several adjacent samples had been previously analyzed for clay properties to assess the potential for fluid damage during the coring process and it was determined that only stable clay phases were present posing little potential for fluid induced damage.In order to provide a uniform testing standard, all samples were cleaned using a toluene solvent extraction process. The samples are all within the dry gas zone of the Montney Formation and typically a stage drying process would be applied to remove residual water. However, with the dominant use of oil based drilling fluids, the decision was made to extract all samples to eliminate the potential effects of drilling fluid invasion. After extraction, MICP samples were crushed and sieved to a size of 5 to 10 mesh (2-4 mm) which provides suitable area to facilitate intrusion in tight rocks. The samples were then dried at 100oC for 24 hours in a vacuum oven to evacuate all connected pore space.

Permeability Measurement:Throughout the years, methods have been developed for permeability estimation for tight sands on both crushed samples and plugs (Luffel and Guidry, 1989; Luffel and Hopkins, 1993; Egermann et al. 2003; Cui et al. 2009; Yang and Alpine, 2010; Clarkson et al. 2012). Clarkson et al. and Yang and Alpine developed methods for profiling permeability using core plugs while others focused on crushed samples. Measuring pulse-decay permeability of plugs has its own obvious benefits, such as sampling a larger and perhaps more representative section of the reservoir and the possibility of testing the effect of changing confining and pore pressures on permeability (Heller et al. 2014). The disadvantage of using crushed samples is the elimination of fractures and the inability to observe the rock in its intact form. Heller et al. argued that although fracture permeability would dominate reservoir performance during the initial phase of the production, it is matrix permeability that controls the performance of a reservoir in the long run.

Matrix Permeability:A helium pycnometer was used to measure the skeletal density of the crushed sample. Helium was used to maximize penetration of pore space and minimize potential reactions with the samples (Cui et al, 2009). The helium pycnometer is comprised of sample and reference cells of known volume and a pressure transducer. The crushed sample was loaded into a sample cell and sealed. The reference cell was filled with helium and after the pressure within the reference cell had equilibrated, the pressure was recorded. The reference cell and sample cell are then opened to each other, allowing the helium from the reference cell to enter the sample cell. By recording the pressure after the system has reached a new equilibrium, the volume of the system can be calculated using Boyles gas law (P1V1=P2V2). The difference between the known volume of the sample cell and the measured volume of gas is equal to the skeletal volume of the sample. Skeletal density was then calculated from the weight of the sample.Permeability was measured on the crushed and sieved sample. Screens of mesh sizes 20 and 35 were used to sort the sample to a uniform particle size (approximately 0.67 mm). The same procedure as described above (for skeletal density) is used to collect pressure decay data during the analysis. The late time pressure decay data was used to calculate permeability via a method refined from ResTech (1996) and Luffel et al. (1993). Permeability was calculated at ambient conditions and, although widely quoted in industry, was not calibrated to in situ conditions. Reported values are therefore to be used only for comparative purposes.

Pulse-Decay Permeability:Plugs of approximately 30.00 mm (1.18) diameter were drilled, using water as the coolant and air as the circulating fluid, from the preserved core. The plugs were cut to approximately 15.00 to 20.00 mm (0.6 0.8). Before assembly into the apparatus the samples were end trimmed, with no circulating fluid or coolant, to ensure two parallel ends 90 to the plug axis. Each plug was cleaned to remove free fluids (oil and water). A modified Hoek cell was used for carrying out the permeability experiments. The sample was placed inside the membrane jacket of the Hoek cell and held tight between two steel pistons with inlet and outlet gas flow fittings. Biaxial confining pressure was applied to create an isotropic stress field. Specific confining stress is defined by the pressure conditions at the depth at which the formation was sampled. The same pore pressure was used for all samples. The first confining pressure level was reached in five stress increments by applying radial and axial confining pressures separately. Throughout the analysis the pressures in the system were recorded using digital pressure transducers. After the desired confining pressure is obtained, the assembly is connected to the pulse-decay measuring unit and data was continuously logged at a prescribed time interval. Data was acquired and analyzed using Trican Geological Solutions proprietary software. Permeability samples was measured with helium using a variation of the pulse-decay technique as described in studies by Jones (1997) and Cui et al (2009). The pulse-decay method involves creating a pressure difference between the tightly jacketed sample and upstream and downstream reservoirs collecting pressure pulse-decay data from the upstream reservoir and the corresponding increase in the downstream reservoir. Permeability measurements were made using helium gas. Helium was used in order to minimize the potential adsorption of the test gas into the sample organic matter, which would in turn have an effect on the measured permeability (Cui et al, 2009). Pulse-Decay measurements were carried out as per the general procedures detailed in Jones (1997) and Cui et al. (2009). The upstream, downstream and differential pressures data were processed using the following equation to calculate the permeability of the sample using: (1)where is the effective permeability to gas in mD, is the slope of the linear equation, is the viscosity of gas in cP, L is the of the cylindrical core plug in cm, is the gas compressibility correction factor, is the mass flow correction factor, A is the cross sectional area of cylindrical core plug in cm2, is the mean absolute pore pressure in psi, and are volumes of upstream and downstream reservoirs respectively in cc.Initially, permeability values determined from the two methods were compared. Pulse-Decay measurements are mostly affected by the possible fractures present in the rock body while GRI permeability only observes the matrix permeability (Clarkson et al. 2012). Figure 1 is a comparative plot of permeability measured using both methods. Both values are in milidarcies and as is shown in Figure 1, all GRI permeabilities fall in the nanodarcy range while there is a wide range to pulse-decay permeabilities. From Figure 1, it could be concluded that matrix permeability for most samples fall within the 10-100 nanodarcy bracket while, possibly due to the presence of micro-fractures (either induced or natural), pulse-decay permeability results differ greatly from that of the matrix. Pulse-Decay permeability tends to be highly affected by fractures, because due to the decreased resistance against flow, flow through fractures dominates the total flow through the plug. In Figure 1, only a handful of samples show proximity between pulse-decay and matrix permeabilities which could be either because the plugs are fracture-free or the fractures were closed as a result of applied overburden pressure. These plugs, as seen in the graph, all have low permeabilities (in the nanodarcy range).An electron microscopy (SEM) analysis was done as a complimentary study to observe the structure of the samples. The SEM analysis (Figure 2) reveals the presence of microfractures in the samples which as explained before, can have a significant impact on flow properties of the rock.

Figure 1 A comparison between Matrix and Pulse-Decay permeability measurements for the 53 samples. Pulse-Decay permeability is measured on plugs under reservoir conditions and Matrix permeability is measured on crushed samples (known as the GRI method). The dashed line is the one-to-one line on which permeabilities measured using the two methods are equal.To verify the validity of the measurements, results of another study done by Derder (2009) were investigated. In his study, Derder performed profile permeability measurements using pulse-decay permeameters at confined pressure (to correct for in-situ conditions) on samples from unit C of the Lower Triassic Montney formation. He reported measured permeability values of 0.0008 to 0.03 mD. These values fall close to pulse-decay permeability values measured in current study on the 53 samples. Derder then correlated permeability and porosity with pore size distribution.

Figure 2 A magnified image of one of the samples. The image highlights the presence of micro-fractures in the Montney rock (red arrows). These fractures could be either natural or induced.Researchers have proposed various correlations to relate permeability with porosity and pore size distribution. Based on the method developed by Winland (1972) and Pittman (1992), a representative pore throat diameter was defined which corresponds to a mercury saturation of 35% and is known as R35. Derder concluded that using Winlands equation as follows:(2)R35 values fall between 0.05 and 0.1 m. In Winlands equation, k is permeability in mD, R35 is in microns and is in decimal. The same method was used in this study to calculate R35 and compare the results with reported values of Derder, the results are shown in Figure 3.

Figure 3 Winland plot of correlating permeability and porosity with a representative pore diameter (R35). In this plot blue dots are permeability values measured using the pulse-decay technique while red dots are matrix permeability values measured using the GRI method.For this purpose, both pulse-decay and matrix permeabilities were used along with helium porosity to correlate permeability and porosity with pore diameter. As can be seen in Figure 3, as expected, pulse-decay permeability cover a wider range of R35 values due to the presence of microfractures, ranging from about 2 nanometers to 1 micrometer, while matrix permeabilities, falling over a smaller range of values, correspond to a smaller range of R35 values lying between 1.5 and 10 nanometers. This analysis indicates that the nano-pore size dominates and impacts production from the Montney formation, just as Derder concluded. Mercury Porosimetry:Since Washburn proposed his popular method for correlating entry pressure with pore radius in 1921, mercury intrusion has been widely used by the petroleum and geoscience community for rock characterization and pore throat size distribution (TSD) analysis; however its use is not limited to the evaluation of pore volumes or TSD analysis only (Leon 1998). Compared to other characterization methods, mercury porosimetry has proven to be a lot faster and more importantly, covers a wider range of pore sizes, from larger macropores to finer mesopores of up to 3.6 nanometers in diameter based on current available commercial porosimeters (Chalmers et al., 2012; Leon 1998; McEnaney, 1995). Mercury intrusion has been used as a characterizing tool in the petroleum industry for decades and has been developed greatly since it was first introduced by Purcell in 1949. The emergence of shales as potential oil and gas plays in North America has encouraged the industry to modify the methods used on conventional reservoir rocks to help characterize shale plays (Comisky 2011). In the current study, mercury porosimetry was carried out on 53 samples using a Micromeritics Autopore IV 9500 series porosimeter and a 5 cc solid sample penetrometer. The intrusion process starts with a vacuum stage which evacuates the penetrometer and pore space within the sample. The penetrometer is then flooded with mercury and low pressure is applied up to 207 KPa (30 psi). The penetrometer is removed from the system and is weighed to record the penetrometer + sample + mercury mass which is used to calculate the bulk density of the sample. The penetrometer is then loaded into a high pressure port and pressure is applied using oil in a series of incremental pressure steps up to a maximum of 414 MPa (60,000 Psi). The volume of mercury intruded is measured as a function of the change in the electrical capacitance of the penetrometer stem as mercury is displaced out of the stem and into the sample. The diameters of the pores the mercury is intruded into at a given pressure step are calculated from the Washburn equation:(3)where D is pore diameter, P is applied pressure, is surface tension and is contact angle.Triple distilled mercury is used to ensure optimum test conditions and consistent physical properties. Testing under these conditions assumes a mercury surface tension of 485 dynes/cm and a contact angle of 130o.Once the mercury injection has reached the maximum pressure of 60,000 psi, the test is stopped and both porosity and bulk density are determined using (Comisky, 2011):(4)and(5)where is the bulk density in g/cm3; and are the weight of the sample, weight of the apparatus including the sample and mercury, and weight of the empty penetrometer respectively, all in grams; is the volume of the penetrometer in mL; is the total volume of the mercury injected at 60,000 psi in mL and is the conformance volume which is a critical term for calculating the bulk density and porosity and analyzing the capillary pressure data.Conformance is defined as a measure of the amount of mercury required to envelope a sample before it starts entering the actual pore network and was first discussed by Wardlaw and Taylor (1976) and Sneider et al. (1997) and later implemented by Shafer and Neasham (2000) and Webb (2001) as a source of error when calculating petrophysical properties of rocks. Bailey (2009) and Comisky (2011) were among the first to address conformance in mercury porosimetry tests done on crushed samples. In crushed samples, because of the increased surface area, conformance has a greater presence when running mercury porosimetry tests. In the current study, the approach discussed by Comisky and Bailey was used to recalculate porosity values form the MP test and these values were then compared with the original porosities from the MP test and GRI porosity. Results of this comparison are shown in Figure 4. Compared with original MP porosity, conformance corrected porosities shrunk an average of 0.5 porosity unit; however, there is significant disagreement between mercury derived porosity and GRI porosity (for both original and conformance corrected porosities). Average GRI porosity is 5.9 % which is more than twice the average conformance corrected mercury porosity of 2.7 %. It could be concluded that more than half the pore network is not accessible to mercury.The contrast between MP and GRI porosity contradicts the findings of Olson and Grigg (2008) and can be correlated with the fine size of the pore structure. As was discussed earlier, only pores of 3.6 nm and bigger are accessible to MP while all pores larger than 0.3 nm are accessible to GRI pycnometry. As discussed earlier (Figure 3) due to the very fine nature of the pore network of the crushed samples, the contrast between the two porosities is expected.

Figure 4 Comparing original and conformance corrected mercury derived porosity with GRI porosityThe same conformance analysis was performed to correct the capillary pressure data derived through mercury porosimetry. The rationale behind this correction, as ComisKy (2011) and Bailey (2009) put it, is because of two phenomena that occur during the mercury porosimetry test. Before any mercury enters the pore network, as pressure increases mercury tends to fill the volume between the crushed particles during the low pressure cycle. As pressure increases, more mercury is injected into the penetrometer and this volume increase is attributed to samples being compressed as a result of pressure increase (Bailey 2009). Comisky (2011) claims that the first actual intrusion into the pore network happens at pressures greater than 1000 psi for tight shales. For this analysis, a pore volume compressibility factor introduced by Bailey (2009) was calculated as:(6)Here, is the compressibility factor in psia-1 and is the mercury pressure in psia. for one of the samples is shown in Figure 5. In other words, is a representative of how intrusion volume changes with an increase in pressure. This could also be observed by plotting the derivative of the capillary pressure curve. The derivative of the capillary pressure curve represents the change in intrusion volumes as intrusion pressure increases. Once the first pores are intruded, the rate with which pressure increases for the rate of intrusion volume to stay the same drops until all the pores accessible by mercury are occupied. Figure 5 and Figure 6 illustrate how conformance and intrusion pressures can be identified using the compressibility and the derivative of capillary pressure curve. In Figure 6 the same conformance and intrusion pressures used in Figure 5 are plotted to show how the derivative curve can be used for conformance and intrusion pressure analysis. Conformance pressure can be used as a cut-off for pore volume studies because it depends surface pores which are exposed due to crushing the samples. Intrusion pressure, on the other hand, can be used for connectivity and deliverability studies because the surface pores do not contribute to flow properties of the sample. Figure 7 shows what the capillary pressure curve would look like after being corrected for intrusion and conformance pressures.

Figure 5 Plot of compressibility and incremental intrusion as a function of injection pressure. Conformance and intrusion pressures are marked on the graph with the red and purple vertical lines respectively.

Figure 6 - Plot of capillary pressure curve and its derivative as a function of mercury saturation for the same sample depicted in Figure 5. Conformance and intrusion pressures are marked on the graph with the two red and purple vertical lines respectively.

Figure 7 A plot of the original, conformance corrected and intrusion pressure corrected capillary pressure derived through the mercury porosimetry test. The same conformance and intrusion pressures used in Figure 5 and 6 are used for corrections.When analyzing MP data, it was noticed that the capillary pressure curves follow two distinct patterns. With type A, intrusion occurs at pressures well above 1,000 psi (close to 6,000 psi in the case shown in Figure 8). Once intrusion happens, the capillary pressure curve flattens and keeps increasing with a fixed slope until injection pressure reaches the maximum value (60,000 psi in the curent study). Type B however, behaves differently. In Type B, intrusion occurs at pressures well below 1000 psi (Close to 100 psi in the case shown in Figure 8). After the larger pores are filled with mercury, pressure keeps building up and a second round of compression occurs. This is confirmed by a compressibility comparison between the two types, shown in Figure 10. A second round of intrusion into the finer pores (if present) could occur as injection pressure increases resulting in a bimodal pore size distribution; however, in the current study a second round of intrusion didnt happen for any of the samples. As the porosity study showed earlier, a large portion of the pore network is not accessible to mercury, which indicates the high probability of Type B samples being bimodal. Figure 9 illustrates the throat size distribution for the two sample types.

Permeability Prediction:The petroleum literature is replete with models that use mercury porosimetry data to predict flow properties of the rock (Purcell, 1949; Swanson, 1981; Winland, 1980; Katz-Thompson, 1986; Pittman, 1992). A comprehensive comparison of these methods on tight gas sands is done by Comisky (2007) in which Klinkenberg-corrected permeability is measured in 63 tight gas sand cores. Various available mercury porosimetry based models are then used to predict permeability and results are compared with measurements. Measured permeabilities for the samples range from 0.0001 mD to 0.2 mD, well above the range of permeability in the current study. Comisky concludes that all the models fail to make reasonable predictions for the sample set. Comisky attributes this to the fact that none of the models were developed exclusively for tight reservoirs.In the current study, an REV model developed by Ruth et al. (2012) is used as the predictive model. The model simulated the pore network with non-interconnected Representative Elemental Volumes (REVs).

Figure 8 A comparison between the two type of samples based on how they react to the mercury porosimetry test. Type A samples are believed to be unimodal while Type B samples are believed to be bimodal.

Figure 9 Comparing throat size distribution for the two types of samples. Normalized incremental intrusion is achieved by dividing incremental intrusions by total intrusion for each sample to correct for different pore volumes. As it is shown, Type B samples have larger throats as intrusion occurs at a lower pressure; however, with the increase in pressure, what is believed to be a second round of compaction occurs.

Figure 10 - A compressibility study on the two types of samples. As seen in red, a second round of compression occurs between 1,000 and 10,000 psi in the type B sample shown here. Type A samples are believed to be unimodal while Type B samples are believed to be bimodal.Comparing Poiseuille flow with Darcy flow in the simulated network, the model correlates permeability with a representative tube diameter and a mean tube length, calculated through tortuosity, as follows:(7)Here, is the porosity, is a representative tube diameter, is tortuosity, and k is permeability. Ruth et al. use Purcells method (1949) for calculating from mercury porosimetry data as follows:(8)where is the interfacial tension, is the contact angle, is the saturation of the vacuum and is the capillary pressure. They also use Archies principle to correlate tortuosity with electrical properties of the rock, such that:(9)where a and m are saturation exponent and cementation factor respectively, and are calculated from electrical tests or through formation factor studies.The REV method has been tested against gas permeability and has been compared with other predictive methods previously (Ruth et al., 2012; Salimifard et al., 2015). It has proven to make better predictions on conventional rocks compared to other popular methods. In this study, the method is used for the first time to predict permeability of tight shale rocks. As a first step, to calculate a representative tube diameter, intrusion-corrected capillary pressures were used. Intrusion pressure for each sample is determined using the peak of the capillary pressure curve. In this stage, 3 samples (samples 21, 34 and 44) were removed from the suite of samples because we were unable to determine a cut-off point to correct for intrusion either by analyzing the capillary pressure curve or by using compressibility or incremental intrusion data. Capillary pressure, derivative of capillary pressure, incremental intrusion and compressibility for these samples are illustrated in Figure 11and Figure 12.

Figure 11 - Capillary pressure data and derivative of capillary pressure analysis for samples 21, 34 and 44When calculating tortuosity, in the absence of electrical data, Ruth et al. suggested that values of 1 and 2 can be used for a and m respectively as a general rule of thumb. Because the size of the helium atom is closer to the molecular size of the gases that are produced from the Montney formation, helium porosity was used in calculations of tortuosity as it accesses more of the pore network compared to mercury porosity. Finally, the REV method is used to estimate permeability for the 50 remaining samples. These estimations are compared with matrix (GRI) permeability for two reasons: first, both GRI permeability and mercury porosimetry measurements are performed on crushed samples, and both focus on properties of the matrix and disregard the presence of microfractures. Second, the REV method implements Poiseuilles and Darcys principle for flow in porous media, both of which are not developed for fractured media. This makes the REV model incapable of simulating fractured media. The result of this comparison is illustrated in Figure 13.

Figure 12 Incremental Intrusion data and Compressibility analysis for samples 21, 34 and 44.

Figure 13 Comparing the results of permeability predictions using the REV method with measured matrix permeability. The solid line is the one-to-one line on which predictions match measurements. The two dashed lines are the 10 fold lines.As illustrated in Figure 13, theres a general under estimation for Type A samples while Type B samples are generally over estimated. The over estimation of Type B samples can be attributed to the fact that mercury porosimetry only accesses the larger pores that are initially intruded by mercury at very low pressures. As a result, when calculating the representative tube diameter using Purcells equation, a larger tube diameter is calculated because the smaller pore network is not included in the calculations.To resolve the problem, it was decided to choose a pressure larger than the intrusion pressure as the cut-off point on capillary pressure curve. To be consistent, the peak of incremental intrusion curve was used as the new cut-off point for Type B samples. This pressure is slightly larger than the intrusion pressure for most Type B samples. The new curves were used to recalculate the representative diameter and new predictions were made using the REV method. As expected, the predictions fell closer to the one-to-one line, improving the overall prediction results for the whole suite of samples. Updated predictions results are illustrated in Figure 14.

Figure 14 - Comparing the updated results of permeability predictions using the REV method with measured matrix permeability. Using the peak of incremental intrusion data as the new cut-off point improves the predictive power of the method for Type B samples.Conclusion:In this study, the pore structure of the Montney Formation was examined using high pressure mercury porosimetry, helium pycnometry, SEM imaging and pulse-decay permeametry. Based on the current study the following conclusions can be made: A comparison of pulse-decay and matrix permeability indicated the presence of microfractures in the medium which is a typical characteristic of the shale formations and SEM images confirmed the presence of microfractures. A study on Winlands R35 indicates that a significant portion of the pore network in the sample set that was studied has pore radii of few nanometers. Comparing mercury porosity and helium porosity indicate that in average, more than half of the pore network for this sample set is not accessible to mercury at applied pressure. Study of the capillary pressure indicates that the derivative of capillary pressure curve can be used along with the compressibility factor to find appropriate cut-off values for conformance and intrusion pressures. Capillary pressure analysis along with compressibility factor analysis indicated the presence of two groups of samples with different behavior in the sample set. The study suggests that Type B samples are bimodal based on their behavior in mercury intrusion test. A permeability predictive method was used to estimate permeability for the two groups of samples. The predictions for Type B samples are improved when a smaller pore diameter is chosen based on the incremental intrusion data. The REV method, while not being exclusively developed for tight sands, makes interesting predictions. It should be taken into account that electrical properties were not available for the current study and Ruth et al. showed that the availability of electrical properties can improve the predictions. It should also be considered that the REV method does not use any fitting parameter and only used rock properties collected through experiments and does not use any fitting parameter.Mercury porosimetry and helium pycnometry have proven to be strong experimental methods that provide us with valuable information about the structure of the pore network. There are various available methods that provide similar information. As Saidian et al. (2014) discuss, each method is based on a unique physical phenomena and measures a different portion of the pore space. Combining the results of these methods can provide us with similar yet supplementary information that can improve our understanding of the pore network. For the current sample set, due to the very fine nature of the pore network, gas adsorption techniques can provide valuable information about the pore size distribution. N2 adsorption technique has been used on mudrocks (Saidian et al., 2014; Clarkson et al., 2012) and has proven to be an efficient technique for characterizing fine-grained rocks.

Acknowledgement:The authors would like to thank Trican Geological Solutions for providing the authors with the test results and granting permission to publish the information presented in this study. We would also like to thank National Sciences and Engineering Research Council of Canada for funding this research.

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