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Insight into the pore structure of tight sandstones using NMR and HPMI measurements Jin Lai, Guiwen Wang, Zhuoying Fan, Jing Chen, Shuchen Wang, Zhenglong Zhou, and Xuqiang Fan Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b01982 • Publication Date (Web): 01 Nov 2016 Downloaded from http://pubs.acs.org on November 6, 2016
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Insight into the pore structure of tight sandstones using NMR and HPMI measurements Jin Lai a,b, Guiwen Wang a, Zhuoying Fan a, Jing Chen a, Shuchen Wang a, Zhenglong Zhou a, Xuqiang Fan a
a. State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum-Beijing, 102249, China b. College of Geosciences, China University of Petroleum-Beijing, 102249, China
Corresponding author: Dr. Jin Lai, China University of Petroleum-Beijing, 18 Fuxue Road, Changping District, Beijing, China, 102249. Tel.: +861089733435; Fax.: +861089734158; E-mail:
[email protected] Abstract: Laboratory measurements including porosity, permeability, High-Pressure Mercury Intrusion (HPMI), Nuclear Magnetic Resonance (NMR) measurements and microscopic analysis of thin sections and scanning electron microscopy (SEM) were performed to provide insights into the microscopic pore structure of the Xujiahe Formation tight sandstones in Sichuan basin. The relationships between microscopic pore structure parameters such as pore geometry, pore size distribution, pore network and macroscopic consequences such as permeability, reservoir quality index, swanson parameter, fractal dimension as well as NMR parameters have been investigated. The results show that the pore systems are dominated by secondary dissolution porosity with minor amounts of primary porosity and micro-fracture. NMR T2 pore size distributions are either uni- or multi-modal. Long T2 components are not frequently present due to the lack of the macropores, whereas as shorter T2 components dominate the T2 spectrum. T2gm (the geometric mean of the T2 distribution) shows good correlations with movable porosity and irreducible water saturation. The pore throat 1
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distributions from HPMI analysis show uni- or multi-modal, and are narrower than the NMR T2 pore size distribution. The rapex, which is the apex of the hyperbola of Pittman.(1992), is well correlated with the entry pressure, r35 and r50. The pore throats larger than rapex, which only account for a small fraction of the pore volume, dominate the permeability of the reservoir rocks. Skin effect, high working pressure as well as over-simplification of cylinder pore shapes result in the high fractal dimension of the larger pores (>rapex). The smaller pores, which can be quantitatively characterized by the fractal dimension, control the microscopic heterogeneity of reservoir rocks. The reservoir quality index (RQI) shows good relationships with both the NMR parameters such as T2gm and the HPMI parameters such as rapex. Integration of routine core analysis with HPMI test and integration of routine core analysis with NMR measurements show that the RQI, which links the pore-throat sizes resulted from HPMI tests with the pore-size distribution from NMR measurements, is a good indicator to reservoir heterogeneity in terms of macroscopic reservoir property and microscopic pore structure. Key words: Tight gas sandstones; pore structure; reservoir quality; Xujiahe Formation
1. Introduction The Upper Triassic Xujiahe Formation, which is a succession of continental, coal-bearing strata, hosts one of the most important petroleum systems in the Sichuan Basin [1-3]. Many researchers hold the view that the Xujiahe Formation gas pools are self-generated and have self-storage [1-2,4]. Significant exploration achievements have revealed great potentials for the natural gas exploration of the Xujiahe Formation in the Sichuan Basin (Fig.1) [2]. Due to the extensive diagenetic modifications the Xujiahe Formation had experienced during the geological history, however, the reservoirs are characterized by low porosity, low permeability, complex pore structure and strong heterogeneity [5-6]. In order for the efficient natural gas exploitation, insights should be provided into the microscopic pore structure of Xujiahe Formation
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reservoir rocks. Reservoir characterization aims at characterizing the spatial distribution of petrophysical parameters such as porosity, permeability or water saturation [7]. Microscopic pore structures (pore size and shape, pore size distribution, pore connectivity) are the most important factors affecting the macroscopic reservoir quality (porosity and permeability) [8-10]. Understanding and characterizing the pore structure of reservoir rocks is of fundamental importance to exploration and efficient development of natural gas [11]. Various experimental methods such as SEM, low-pressure N2 adsorption and neutron scattering techniques have been used to characterize pore structures [12-14]. Mercury porosimetry is the fastest method of determining the capillary pressure curves, in which is embedded information about a wide range of pore sizes of reservoir rocks [15]. NMR measurements of relaxation times are widely used to characterize the pore structure and pore fluids in rocks quickly and nondestructively [16]. Laboratory NMR measurements performed on saturated core plugs can provide valuable information for estimating pore fluid pressure, fluid flow rates, and the transverse relaxation time (T2) distributions can be used to construct a pore-size distribution and estimate permeability and capillary pressure curves [16-18]. Because of the complexity and irregularity of the pore structure, it’s difficult to characterize pore structure by traditional Euclidean geometry [10-11]. The fractal geometry can be adopted to describe irregular geometrical shapes with nonintegral dimensions [12-19]. An integrated analysis of NMR and HPMI tests using fractal theory could provide importance insights into the microscopic pore structures of the reservoir rocks. The major goals of this paper are to investigate the pore systems, pore size distribution, and pore networks of Xujiahe Formation tight gas sandstones from the Sichuan Basin of China. NMR relaxation time distributions were combined with HPMI analysis to provide insight into the nature of the pore structure including pore geometry, pore throat distribution and accessible versus inaccessible porosity as well as the fractal dimensions of the reservoir rocks. Integration of porosity-permeability values, pore-throat sizes resulted from HPMI tests and pore size distribution from 3
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NMR measurements was carried out to investigate the effects of microscopic pore structure parameters on macroscopic reservoir property of reservoir rocks. A comparison and evaluation of parameters derived from HPMI and NMR tests is presented in this study, and regression analysis is used to build the interrelationship between these parameters. This work provides insights into the microscopic pore structure and heterogeneity of reservoir rocks, and builds the relationships between microscopic pore structure parameters and macroscopic consequences of reservoir quality using a combination of NMR and HPMI measurements, and has potential application in tight gas sandstone reservoir rocks with similar geological setting elsewhere. These insights are of great importance for industry engineering systems such as natural gas exploration and hydraulic engineering.
2. Geological setting The Sichuan Basin, with an area of 188,000 km2, is located in the Southwest China [20]. The basement of the basin is a united craton, which is known as Yangtze Paraplatform [21]. The basin could be divided into Eastern, Southern, Western and Central Sichuan hydrocarbon accumulation zones according to the nature of basement and petroleum genetic types (Fig.1) [1-2]. During the Early and Middle Triassic, the cratonic margins were raised due to the compression from the Tethys and the Pacific [21]. Thick carbonate successions dominate the Permian to Middle Triassic stratigraphic records, including the Upper Permian Longtan (P2l) and Changxing (P2c), Lower Triassic Feixianguan (T1f), Jialingjiang (T1j) and Leikoupo Formation (T2l) [1,3,20]. Several episodes of the Indo-Sinian orogeny resulted in large folds at the end of Triassic, and then a series of lacustrine and deltaic clastic sediments were deposited, known as the Upper Triassic Xujiahe Formation [21]. The Jurassic and Cretaceous sediments in the Sichuan Basin are mainly composed of continental redbeds [20]. The Upper Triassic Xujiahe Formation can be divided into six Members based on lithological associations and sedimentary cycles. Among them, the T3x1, T3x3 and T3x5 members, which are composed of mudstones and shales, act as the source rocks and cap rocks for the Xujiahe oil and gas accumulation. In contrast, the T3x2, T3x4 and 4
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T3x6 members, which were formed in the braided delta front depositional facies, are composed of fine to medium-grained sandstones and conglomerates, and they act the main reservoir rocks for the Xujiahe oil and gas accumulation [2,3,6]. The Xujiahe formation contains most of the proven gas fields (such as Zhongba, Pingluoba, Jiulongchang, Guang’an, Hechuan, and Anyue gas fields) and undiscovered gas potential in the Sichuan Basin (Fig.1) [1]. Nevertheless, the Xujiahe reservoirs are characteristic of low porosity, low permeability and strong heterogeneity due to the diagenesis the reservoirs had experienced [6]. In order for the further natural production, integrated methods should be performed to provide insights into the microscopic pore structure of reservoir rocks.
3. Samples and analytical methods Routine core analysis (grain density, porosity, Klinkenberg corrected permeability and air permeability) was performed on 30 samples under the net confining stress (NCS) of 363 psi (2.5MPa), and 5800 psi (40MPa), respectively. The instrument CMS-300 was used for the porosity and permeability measurements. Thin section samples were impregnated with blue epiflourescent epoxy to highlight porosity. SEM analysis was conducted on the freshly broken surface (carbon coated) to analyze the pore-throat characteristics. NMR measurements were performed on a subset of 23 core plug samples to determine the T2 distributions for both saturated (100% brine) and centrifuged status using a MARAN Ultra instrument operating at a proton Lamor frequency of approximately 2 MHz. The experiment temperature was set at 28 °C degree. The waiting time of NMR apparatus is 6000 ms, and the echo spacing is 0.2 ms. The signal/noise ratio for the laboratory NMR measurements was a minimum of 100:1. The samples were firstly fully (100%) saturated with synthetic formation brine, and the NMR T2 distributions (incremental and cumulative) were measured. Then the core plug samples were removed from the free movable water by a centrifugal machine, and the NMR T2 distributions were also measured. The rotation rate of the centrifugal machine is 9000 r/min, and the corresponding capillary pressure is about 100 psi. The resulting NMR data was used to distinguish capillary-bound
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water plus clay-bound water from free water. HPMI analysis was performed at last on a total of 30 core plug samples (1.5 inches in diameter and 1 inch in length) in The Houston Advanced Technology Center of Core Laboratories. The porosity and permeability of these 30 core plugs are measured at 800 psi (5.5 MPa). The sample depth ranges from 3024.98 to 4324.92m. A mercury porosimeter, of which the maximum injection pressure is 55,000 psia (379MPa), was used to force mercury into all accessible pore radius (>0.00196 µm) and measure the volume of mercury entered into the pores. The pore volume connected by each characteristic pore radius is equal to the mercury volume (VHg) injected into at the corresponding capillary pressure [22].
4. Results and Discussions 4.1. Petrophysical properties and pore systems Presented in Figure 2 is the porosity and air permeability measured under the net confining stress of 2.5MPa and 40MPa. The permeability generally shows a good exponential relationship with porosity. The porosity does not change much with stress. The permeability measured at 2.5MPa stress is generally less than 1 mD, and is less than 0.1mD under the net confining pressure of 40MPa, which indicate the Xujiahe Formation sandstones belong to tight gas sandstones reservoirs [6,23-24]. The air permeability decreases rapidly with the increasing stress (Fig.2). The confining pressure applied on the samples during petrophysical measurements potentially closes part of the stress sensitive pores and pore throats [25]. A wide range of pore systems from primary intergranular pores, intragranular pores to micropores are visible in transmitted light microscopy (Fig.3). The pore systems in Xujiahe Formation sandstones in Sichuan Basin are dominated by secondary dissolution pores, whereas the primary pores are relatively rarely observed [5,6,23]. Under microscopic observations, many feldspars and rock fragments contain abundant intragranular pores due to partly to completely dissolution (Fig.3A) [23]. In some samples with abundant rigid grains, and are characterized by coarser-grained and good sorting, some primary porosity could be preserved (Fig.3B). Authigenic clay minerals such as illite and
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mixed-layer illite/smectite are abundant with micropores (1000 ms) are not frequently present [30]. In fact, there are minor peaks or a tail distribution of T2 relaxation time larger than 1000 ms that are most likely related to the macropores. Instead the main T2 appears as a major dominant peak at the shorter T2 relaxation times (Fig.4; Fig.5). Especially for the sample in Fig.4B and Fig.5B, the T2 distributions are dominantly T2s components, and the corresponding T2peak and T2gm values are low. Therefore the micropores, which are usually poorly connected, correspond to the short relaxation time components in the T2 distribution, and the micropores have a great effect on the heterogeneity and pore structure of the reservoir rocks. The more abundant in micropores, the more fluids will be bounded, 9
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and the pore structure becomes more heterogeneous. The combination of intergraular pores, intrgranular pores and micropores in the Xujiahe sandstones results in a complex NMR T2 distribution. Some samples show T2 components larger than 1000 ms, which is attributed to the presence of micro-fractures. Regression analysis show that the parameter T2peak shows a good correlation with the T2gm, with a coefficient of determination (R2) of 0.9, and the T2gm is generally well correlated with the movable porosity and irreducible water saturation Swi (Fig.6). Therefore, from the aspects of NMR pore size distribution, the T2gm is a sensitive parameter for characterizing the microscopic pore structure.
4.3. Pore-network characteristics Mercury intrusion experiment is widely used for the determination of total pore volumes and pore size distributions for reservoir rocks [34]. Mercury intrusion is used for characterizing mesoporosity and macro-porosity, and the HPMI measurements, which requires immense injection pressures to access the finest porosity, are designed to characterize the all the pore systems (including micropores) within tight reservoirs [35]. HPMI analysis demonstrates the heterogeneous nature of the pore networks in Xujiahe reservoir rocks. Figure 7 shows the capillary pressure curves of the four sandstone core samples representing different reservoir quality and microscopic heterogeneities. The mercury saturation is nearly as 100%, and this indicates that almost all the pore systems are accessible to the nonwetting-phase (mercury) due to the high injection pressure (Fig.7). The mercury starts to invade the accessible wide throats first, and an increase in capillary pressure will cause a small change in mercury saturation [22]. From Sample Ⅰ to Sample Ⅳ , the reservoir quality decrease gradually, and it’s obvious that the Sample Ⅳ has the highest entry pressure and heterogeneity. In contrast, the Sample Ⅰ has the highest porosity and permeability, and therefore the lowest heterogeneity (Fig.7). The HPMI analysis shows that the threshold entry pressure is in the range from 0.28MPa to 1.81MPa, and has an average of 0.99MPa (Table.2). The maximum connected pore radius (rmax), i.e., entry radius at which significant invasion of a sample with mercury occurs [36], ranges from 0.41 to 2.70 µm with an average of 10
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0.89 µm. The r50 (pore-throat radius at 50% mercury saturation) varies from 0.033 to 0.36 µm with an average of 0.11µm. The r35 (pore-throat radius at 35% mercury saturation) shows a wide range from 0.068 to 0.75 µm, and averages as 0.22 µm (Table.2). The rapex, which is the apex of the hyperbola of Pittman.(1992) (plot of mercury saturation over capillary pressure against mercury saturation, Fig.8) [37], is in the range from 0.147 to 0.832 µm with an average of 0.34 µm (Table.2). The corresponding Swanson parameter (Swanson, 1981) [38], which is the maximum mercury saturation (%) over capillary pressure (MPa), i.e., (SHg/Pc)max, ranges from 22.7 to 243.2 MPa-1. Figure 9 shows the uni-modal behavior of the pore throat distribution acquired on the sample Ⅰ by HPMI. In contrast, the Sample Ⅳ shows a bi-modal behavior of the pore throat distribution (Fig.10). These results are in consistent with the pore size distribution from NMR T2 measurements (Fig.4; Fig.5). The HPMI analysis shows that these reservoir rocks have complex, heterogeneous microscopic pore structures with uni-modal and bimodal capillary pressure curves, which indicates that the pore systems of the Xujiahe Formation sandstones consist of small to large pore-size domains. The pore throat distribution from HPMI analysis, which provides information about the existence and connectivity of pore throats, is complementary to the pore-body size distribution from NMR measurements [17]. The HPMI pore throat distribution is in general narrower than the NMR T2 pore size distribution (Fig.4; Fig.5; Fig.9; Fig.10). The HPMI test is more sensitive to pore throat sizes rather than pore body sizes, and the HPMI data depend on both the pore size distribution and the connectivity of the pore network [18], whereas the T2 NMR measurements are more sensitive to pore body sizes [16,39]. The pore network from HPMI analysis consists of pore volumes connected through throats [40]. In contrast the majority of the pore volume is assumed to be composed of pore bodies in NMR measurements [16]. Therefore the relationship between HPMI data and NMR pore size distribution is complicated [18]. Pore connectivity is an important factor for fluid flow and mass transport in reservoir rocks [41]. Distributions of pore and throat as well as its connectivity are 11
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crucial factor controlling the reservoir quality and oiliness (oil-bearing property) of tight sandstones [10,42]. In tight gas sandstones, the reservoir quality is mainly controlled by the pore throat and permeability but not the pore spaces [42]. From Figure 9 and Figure 10, it can be concluded that the pore throats greater than rapex make a significant contribution to the permeability. For example, the pore throats with radius greater than rapex only accounts a small fraction (SHg=31.6%) of the total pore volume, however, their contribution to permeability is as high as 82.3% (Fig.8, Fig.9), which indicates that the permeability is controlled by the relatively large pore throats (>rapex). Likewise, in Figure 10, the pore throats with radius greater than rapex only accounts 23.4% of the total pore volume, however, their contribution to permeability is as high as 88.0% (Fig.8, Fig.10). Therefore, in the Xujiahe tight sandstones, the reservoir quality especially permeability is generally controlled by the large pore throats, which account of only a small part of pore volume [42-43]. In addition, the rapex shows a good positive correlation with the air permeability measured under a confining pressure of 800 psi (Fig.11). In addition, the parameter rapex is well correlated with the entry pressure, r35 and r50, which are commonly used for the permeability prediction (Fig.12)[30,44-45]. The maximum pore throat radius (rmax), which corresponds to the threshold entry pressure, is in the range from 0.41 to 2.7 µm with an average of 0.89 µm (Table.2), and it is also evident that the rmax shows a good positive relationship with the air permeability (Fig.13). Therefore, the connectivity of the pore network, which is dependent on the larger pore throats, plays an important role in controlling the microscopic pore structure [46]. Therefore, from the aspects of HPMI pore throat distribution, the rapex and rmax are sensitive parameters for characterizing the microscopic pore structures, and the measured permeability are quite sensitive to the rapex and rmax. By contrast, the micro-porosity usually contributes to total porosity, but is not effective in fluid conduction due to its smaller pore throat radius [47]. The volumes of pores that are controlled by small pore throats (rapex) with good connectivity determine the permeability and reservoir quality of the reservoir rocks. (5) The volumes of pores connected by small pore throats (
