| Citation: | Dongdong Yuan, Qiang Liu, Haijin Xu, Changsheng Zhang, Daozhi An, Meihua Wei, Gaojing Ren. High-Temperature Geothermal Source in the Northeastern Datong Basin, North China: Evidence from the Drilled Rhyolite. Journal of Earth Science, 2024, 35(5): 1776-1780. doi: 10.1007/s12583-024-0035-y
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As an important part of geological evaluation of reservoir effectiveness, pore structure and fluid mobility have always drawn the attention by academia and industry. Especially, as the object of oil and gas exploration gradually changes from conventional sandstone reservoirs to unconventional reservoirs represented by tight sandstones and shales, the integrated evaluation of pore and fluid has become the core of reservoir research (Hou et al., 2021, 2020; Li et al., 2021; Zhang et al., 2016; Hu et al., 2015; Aguilera, 2014; Xiao et al., 2014; Zhu et al., 2013; Loucks et al., 2012; Zou et al., 2012; Timur, 1969). In terms of pore structure characterization, due to the small size of pore throats in unconventional tight reservoirs (Wu et al., 2019a, b, 2015; Zou et al., 2017, 2011; Nelson, 2009), how to improve the resolution and the characterization dimensions, to obtain more comprehensive microscopic pore structure information, has become a research hotspot. Currently, the research has extended from conventional optical microscope to the high-resolution field emission scanning electron microscopy (SEM), and from conventional medical CT to higher resolution micro-CT and nano-CT, focused ion beam scanning electron microscope (FIB-SEM), synchrotron source. Moreover, abundant technologies such as high-pressure mercury injection, nitrogen adsorption, carbon dioxide adsorption, small angle scattering, electrochemical, and nuclear magnetic resonance (NMR) have been adopted (Li et al., 2021; Wu et al., 2019b, 2018; Zhu et al., 2013; Chalmers et al., 2012; Tian et al., 2012; Curtis et al., 2011; Slatt et al., 2011; Zou et al., 2011; Milner et al., 2010; Desbois et al., 2009), which have promoted better understanding of the pore structure of tight reservoirs.
At present, the focus of reservoir research gradually shifts to fluid mobility evaluation. Fluid mobility determines the recoverability and economic value of unconventional oil and gas, and has more direct impact on gas and oil exploration and development (Wu et al., 2019b; Afsharpoor et al., 2016; Milner et al., 2010). Most of the existing fluid mobility evaluation is based on the evaluation of fluid occurrence states. Zhu et al. (2013), Wu S T et al. (2015) directly observed the fluid occurrence states in tight sandstone and shale by using environmental SEM, and discussed the mobility of oil in four identified occurrence state. Wang X Q et al. (2015) used the charging effect of SEM to study the retained liquid hydrocarbons in organic-rich shales. Many other scholars have used numerical simulation methods (e.g., molecular dynamics simulation) to evaluate the existence and mobility of fluids in unconventional reservoirs. Relevant studies have provided valuable evidence to clarify the admissibility of unconventional oil and gas (Afsharpoor et al., 2016; Wang S et al., 2016, 2015; Al-Gharbi et al., 2005).
NMR is the most adopted instrument to evaluate dynamic fluid mobility of tight sandstone in the laboratory (Zhang and Zhang, 2021; Wu et al., 2019b; Li et al., 2015; Yao and Liu, 2012; Li et al., 2008; Hofman et al., 2001; Wang et al., 2001a). The basic principle of NMR is to evaluate the fluid distribution and content according to the relaxation phenomenon of hydrogen nuclei, which cannot be directly related to the pore structure. In order to further associate the movable fluid determined by NMR with the pore structure, mainly two methods are currently used.
(1) NMR combined with centrifugation method. Firstly, the sample is saturated to measure the NMR response, then the sample is placed in different centrifugal forces for centrifugation, and then the NMR response signals are respectively measured; by comparing the differences of nuclear magnetic resonance signals under different centrifugal forces, the saturation of the movable fluid corresponding to different centrifugal forces is determined; the centrifugal force is equivalent to capillary pressure, which could be used for equivalent throat diameter calculation, and then the corresponding movable fluid saturation in different throat range is determined (Wu et al., 2019b; Li et al., 2015; Yao and Liu, 2012). The advantage of this method is that it is easy to operate and can directly establish the relationship between the movable fluid saturation and pore throat structure. However, the disadvantage is that the centrifugal force is relatively small (400 psi, about 2.76 MPa is mostly used for the main space) and the corresponding throat diameter is only 100 nm (Li et al., 2015; Wu S T et al., 2015; Yao and Liu, 2012; Wang et al., 2001b), which is unable to evaluate the distribution of movable fluid in storage space less than 100 nm. Moreover, this method can only be used to evaluate the mobility of single-phase fluid, and cannot evaluate the mobility of oil and water phases, which is different from the actual formation conditions.
(2) NMR combined with core flooding method. Firstly, the sample is saturated with formation water, and then the sample is displaced to bound water by using specially processed oil (usually fluorinated, remove hydrogen nuclei, and no response on NMR), to determine the movable fluid distribution, and then use formation water to displace the sample to the residual oil to obtain the distribution of the movable oil (Wu et al., 2019b; Li et al., 2015). The advantage of this method is being close to geological conditions to the greatest extent, simulating the mobility of different fluids under multi-phase conditions, with large displacement pressure difference, it can comprehensively characterize the fluids existing in the main space of tight reservoirs. However, the disadvantages lie in poor physical properties of tight reservoirs, displacement difficulty and long experimental period, which lead most scholars to adopt centrifugal method combined with nuclear magnetic resonance, and less to adopt displacement method combined with nuclear magnetic resonance (Wu et al., 2019b; Afsharpoor et al., 2016; Li et al., 2015; Wu H et al., 2015; Yao and Liu, 2012).
Therefore, how to effectively apply the core flooding-NMR associated method to the evaluation of movable fluid in tight sandstone still needs further exploration, and the difference between the determined movable fluid saturation and that determined by the core centrifugation-nuclear magnetic resonance combination method needs further discussion. In this paper, the tight sandstones with different physical properties of the Chang 7 Member of the Yanchang Formation in the Ordos Basin selected. After the detailed study of pore structure, the movable fluid was investigated using both core flooding-NMR associated method and core centrifugal-NMR associated method. The movable fluid saturation of tight sandstones of Chang 7 Member was summarized, and the differences of movable fluid from these two methods were also compared and discussed. The results could provide reference for future tight reservoir fluid mobility evaluation and research.
Ordos Basin is located in North-Central China (Fig. 1a), with an area of about 32×104 km2. It is the second largest sedimentary basin in China. Its boundaries include Helan-Liupan Mountain structural belt on the western edge, Qinling orogenic belt on the south side, Luliang Mountain uplift on the east side and Yinshan uplift belt on the north edge (Fig. 1b). The tectonic is stable, which is a typical "craton basin" (Wu et al., 2016; Yang et al., 2016; He, 2003; Yang, 2002). The Yanchang Formation is a key strata for Mesozoic oil and gas exploration in the Ordos Basin, which could be subdivided into ten members from bottom to top. The Chang 7 Member was formed during the maximum lake flooding period, and it could be sub-divided into three layers, including 3rd layer, 2nd layer, and 1st layer from bottom to top. The 3rd layer of Chang 7 Member is dominated by organic-rich shales, forming the most important source rock of the Mesozoic petroleum system in the basin. From the 2nd layer to the 1st layer of the Chang 7 Member, the lacustrine began to shrink, resulting in smaller area of the semi-deep/deep lacustrine and more developed delta system. These are the main exploration targets of recent "self-sourced" resources (Yang et al., 2016). From Dingbian to Qingyang, the whole area was located at semi-deep/deep lacustrine environment during the Chang 7 sedimentation period, and sand bodies of under-water distributary channel of the delta front were continuously prograding to the deep lacustrine area. These sand bodies were reacted and transported to form thick and large scaled sedimentation composite which consisted of multiple delta front and turbidites at the lower part of the slope break zone in the central basin (Yang et al., 2016; Zou et al., 2009). The lithology of tight sandstones in Chang 7 Member was mainly arkose and feldspar litharenite. The percentage of fine-grained sand reached over 70%, and the main porosity and permeability was 5%–12% and less than 1.0×10-3 μm2, respectively (Wu et al., 2019a; Yang et al., 2016).
A total of 98 samples were collected from 12 key wells, and these locations were shown in Fig. 1c. Firstly, the samples were prepared into plugs with diameter of 2.54 cm and length between 2.54 and 5 cm. Porosity and permeability were measured after the hydrocarbon removal using chemical solvent. Twenty-eight samples with different physical properties were selected to investigate the pore structure and fluid mobility. The porosity of 28 samples was ranged from 1.4% to 11.459% (Table 1). Optical microscope, SEM, CT and high-pressure mercury injection were adopted to study pore structure, and then the core flooding-NMR combined method and the core centrifugal-NMR combined method were used to evaluate the movable fluid of Chang 7 tight sandstone. Finally, the relationship between movable fluid and pore structure, and the comparison of two different methods of movable fluid were discussed. This paper introduced the procedure of two evaluation methods of movable fluid.
| Sequence | Sample No. | Porosity (%) | Permeability (×10-3 μm2) | Mobility fluid saturation (%) | Mobility fluid porosity (%) | Mobility oil saturation (%) | Mobility oil porosity (%) |
| Core flooding-NMR combined method | H22-29 | 1.4 | 0.007 1 | 77.76 | 1.09 | 4.50 | 0.063 |
| H22-39 | 3.1 | 0.01 | 72.64 | 2.259 | 3.84 | 0.12 | |
| H22-11 | 5 | 0.02 | 79.58 | 3.98 | 4.85 | 0.24 | |
| H31-04 | 5.9 | 0.03 | 52.82 | 3.12 | 17.54 | 1.03 | |
| H22-19 | 6.7 | 0.038 | 66.32 | 4.44 | 21.654 | 1.45 | |
| H29-03 | 7.8 | 0.055 | 60.72 | 4.74 | 5.59 | 0.44 | |
| H22-23 | 8.6 | 0.084 | 72.94 | 6.27 | 38.87 | 3.34 | |
| H29-01 | 9.1 | 0.093 | 62.61 | 5.69 | 9.66 | 0.88 | |
| H29-04 | 9.8 | 0.101 | 63.15 | 6.19 | 11.27 | 1.10 | |
| C25-05 | 10.3 | 0.174 | 69.64 | 7.17 | 28.56 | 2.94 | |
| H29-14 | 10.9 | 0.253 | 62.58 | 6.82 | 13.83 | 1.51 | |
| H29-16 | 11.1 | 0.344 | 67.55 | 7.50 | 18.52 | 2.06 | |
| Average | 7.5 | 0.101 | 67.36 | 4.94 | 14.89 | 1.26 | |
| Core centrifugation-NMR combined method | A25-05 | 1.62 | 0.000 15 | 7.23 | 0.12 | / | / |
| A24-10 | 5.24 | 0.019 | 29.63 | 1.55 | / | / | |
| A23-14 | 5.51 | 0.009 3 | 32.32 | 1.78 | / | / | |
| A24-11 | 6.42 | 0.046 | 25.37 | 1.63 | / | / | |
| A24-12 | 6.54 | 0.10 | 31.65 | 2.07 | / | / | |
| A26-13 | 6.55 | 0.038 | 49.61 | 3.24 | / | / | |
| A24-14 | 6.82 | 0.006 6 | 10.99 | 0.75 | / | / | |
| A23-15 | 6.90 | 0.013 | 26.99 | 1.86 | / | / | |
| Z23-01 | 8.83 | 0.014 | 37.64 | 3.32 | / | / | |
| A26-14 | 8.95 | 0.11 | 60.29 | 5.40 | / | / | |
| A25-06 | 9.23 | 0.017 | 14.05 | 1.30 | / | / | |
| A23-16 | 9.33 | 0.053 | 53.57 | 4.99 | / | / | |
| A26-15 | 9.83 | 0.14 | 53.63 | 5.27 | / | / | |
| Z23-02 | 10.15 | 0.024 | 40.84 | 4.15 | / | / | |
| A26-16 | 10.57 | 0.16 | 57.81 | 6.11 | / | / | |
| Z23-03 | 10.70 | 0.045 | 44.52 | 4.77 | / | / | |
| Average | 7.70 | 0.050 | 36.01 | 3.02 | / | / |
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The experiment was carried out in the Key Laboratory of Basin Structure and Oil and Gas Accumulation of China National Petroleum Corporation. The NMR instrument used was the Micromr 20-025v instrument from Newmarket Corporation. The main experimental parameters included frequency intensity of 23 mHz, the echo time of 0.2 ms, the waiting time of 6 s, and echo number of 8 000. The water was configured based on the analysis of formation water from the Chang 7 Member, Xin'anbian area, and the concentration of chemical constitution were as follows, i.e., composition included calcium chloride 0.222 g/L, magnesium chloride hexahydrate 6.347 g/L, sodium sulfate 0.447 g/L, sodium chloride 9.58 g/L, and sodium bicarbonate 0.135 g/L. The hydrogen nuclei in crude oil were replaced with fluorine-chlorine substitution reaction, and the experiment temperature was 78 ºC, which was consistent with the formation temperature of the Chang 7 Member. Considering the actual formation pressure conditions and the cycle time of displacement experiments, the displacement pressure difference was set as 5 MPa, which could effectively avoid the formation of artificial fractures caused by excessive pressure difference.
During the experiment, the residual hydrocarbon was extracted with Dean Stark method and the extraction was detected with fluorescence to ensure that the hydrocarbon was removed. In the core flooding process, the sample was first placed in a vacuum, saturated with configured water, and then placed in the NMR instrument to measure the signal response, which was named NMRS1. Then the fluorinated oil was injected to displace the water until the oil flow-out rate remained stable and the water was depleted. The NMR response was measured and named NMRS2. The difference between NMRS1 and NMRS2 represented the movable fluid characteristics of the samples. Finally, the configured water was reinjected into the sample again until the oil output was depleted and the water yield remained stable, and the NMR response characteristics were measured again, which was named NMR3. The difference between NMRS3 and NMRS2 represented the characteristics of the movable fluid in the sample. The single core flooding procedure could last for 10 to 30 days, and the time was mainly affected by the physical properties of the samples. The general physical properties of a single core can be determined by this flooding procedure.
The experiment was carried out at the Institute of Porous Flow & Fluid Mechanics, Chinese Academy of Sciences. The NMR equipment adopted was the same as the core flooding-NMR combined method with the same experimental parameters settings. The configured water composition was the same as described in Section 2.1. Firstly, the rock samples were washed with oil, dried and then re-saturated with configured water, and the NMR T2 spectrum was measured. Then, the samples were placed in centrifuges at different rotational speeds, and the NMR T2 spectrum was measured after each centrifugation. The difference of each nuclear magnetic resonance T2 spectrum was compared to determine the movable fluid saturation under different centrifugal forces. Among them, the centrifugal force could be approximate to the capillary force, and the corresponding throat diameter could be calculated by the following formula.
| Pcf=Pc | (1) |
| Pc=σcosθ/D | (2) |
where, Pcf—centrifugal force, MPa; Pc—capillary force, MPa; σ—interfacial tension, MPa/m2; θ—interface contact angle, º; D—throat diameter, μm.
In this study, four centrifugal forces were set: 20, 40, 200 and 400 psi, with the corresponding throat diameters of 0.1, 0.2, 1 and 2 μm.
Both primary pores and secondary pores are developed in tight sandstones of Chang 7 Member in the study area. The primary pores are mainly inter-granular pores, and the intergranular pores are mainly located between rigid particles such as quartz, albite and volcanic rock debris. The diameter of inter-granular pores ranged from 1 to 50 μm (Fig. 2a), there were not many inter-granular pores. The secondary pores are mainly dissolution pores and intra-clay mineral pores, including inter-granular dissolution enlarged pores (Fig. 2b), feldspar-debris dissolution pores (Figs. 2c, 2d, 2e, 2g, 2h), calcite dissolution pores (Fig. 2f), and clay mineral dissolution pores (Fig. 2f). The two most important intra-clay mineral pores types located among clay mineral crystals are intra-kaolinite (Figs. 2i, 2j) and intra-chlorite pores (Fig. 2k). There are also some intra-illite pores with a pore diameter < 100 nm (Fig. 2l). The pore diameter of secondary pores varies from < 100 nm to 50 μm.
The pore structure model of the 3D CT scan shos that the pore system is positively related to the physical properties of the reservoir (Fig. 3). The porosity of H29-16, H29-01 and H22-11 are 11.1%, 9.1% and 5%, respectively, and the pores in two- dimensional CT slices decreased significantly (Figs. 3a1–3a2, 3b1–3b2, 3c1–3c2), as well as pore system in the 3D model. The pore volume decreased from 12.6×106 to 7.5×106 μm3 and then to 5.2×106 μm3 (Figs. 3a3–3a4, 3b3–3b4, 3c3–3c4), and the corresponding equivalent pore diameter decreases from 100–200 to 20–62.5 μm and then to 2–5 μm (Figs. 3a5, 3b5, 3c5). The equivalent diameter refers to the diameter of the equivalent sphere equal to the pore volume (Wu et al., 2018). It should be noted that the pixel size of the CT scans was 1 μm, therefore the focuses was on the storage space with diameter greater than 1 μm. Considering the complexity of the pore system in tight sandstone, the diameter of the equivalent pore is generally larger than that of actual pores in tight sandstones.
The experimental results of the high-pressure mercury injections show that Chang 7 tight sandstones are characterized by small pore throat diameter, strong heterogeneity and poor connectivity. The lower-limit of displacement pressure ranges from 0.6 to 6 MPa, with an average value of 1.68 MPa. The maximum pore throat diameter ranges from 0.24 to 2.34 μm, with an average value of 1.3 μm. The median pressure is between 2.58 and 40.54 MPa, with an average of 11.22 MPa. The average pore diameter ranges from 21.8 to 33.26 μm, with an average value of 25.56 μm. The diameter of most throat ranges from 0.013 6 to 0.92 μm, with an average value of 0.52 μm. The sorting coefficient is between 0.96 and 2.26, with an average value of 1.64. The skewness is between -0.15 and 2.08, with an average value of 0.47. The maximum mercury saturation is between 73.9% and 100%, with an average of 91.22%. The residual mercury saturation is between 63.04% and 88.9%, with an average of 74.36%. The efficiency of mercury ejection is between 9% and 33.11%, with an average of 18.2%, indicating poor connectivity of the pore throat system.
The pore diameter distribution of Chang 7 tight sandstones is well related to its physical properties. Figure 4 shows the histogram of pore throat distribution of tight sandstone with different physical properties. As it shows, the porosity of Sample A26-16 is 10.57%, and the storage space with pore throat diameter between 0.5 and 1 μm accounts for more than 35% (Fig. 4a); The porosity of Sample A26-14 is 8.95%, and the storage space with pore throat diameter between 0.1 and 0.3 μm accounts for over 45% (Fig. 4b). The porosity of Sample A23-14 is 5.51%, and the storage space with the pore throat diameter between 0.065 and 0.3 μm accounts for over 55%, and the storage space with pore throat diameter less than 40 nm accounts for more than 35% (Fig. 4c). In general, the connected pore-throat system with main diameter less than 1 μm in Chang 7 tight sandstone pore throat system accounts for more than 95%, of which the dominant pore throat diameter is 0.2–0.3 μm, accounting for 30% of the storage space. The pore throat system with diameter less than 100 nm accounts for over 35% of the storage space (Fig. 4d).
Fluorinated oil without hydrogen nuclei is used in this study, and there is no nuclear signal in NMR analysis, so the oil can be effectively distinguished from the formation water. Figure 5 shows the differences of NMR response signals under three different states of saturated water, bound water, and irreducible oil in reservoirs with different physical properties. The difference between the envelope area of the T2 distribution curve in the water- saturated state (the blue line in Fig. 5) and the envelope area of the T2 distribution curve in the bound water state (the red line in Fig. 5) represents the saturation of the movable fluid, and the difference between the envelope area of the T2 distribution curve in the irreducible oil state (the green line in Fig. 5) and the envelope area of the T2 distribution curve in the bound water state (the red line in Fig. 5) represents the movable oil saturation. As the physical properties become better (Figs. 5a–5f), the movable fluid saturation and the movable oil saturation increase sharply, and the T2 distribution curves evolve from the previous single-peak mode to a double-peak mode. From H22-29 to H22-39 to H22-11, their porosities are less than 5%, and the NMR T2 distribution curve shows a single-peak mode on the left; although the right peak increases slightly with the increase of physical properties, the overall proportion is low and the green and red curves almost overlap, indicating that the saturation of the movable oil is extremely low (Figs. 5a, 5b, 5c). From H29-03 to H29-01 to H29-14, their porosities increase from 7.8% to 10.9%; with the improvement of physical properties, the blue, red and green curves become more and more distinguishable and the shape of these curves shows the obvious double-peak model. The amplitude of the overall T2 signal also gradually increases, indicating an increase of the absolute quantities of movable fluid and movable oil (Figs. 5d, 5e, 5f).
Quantitative evaluation results show that the movable fluid saturation of the Chang 7 tight sandstones is between 52% and 80%, and the average movable fluid saturation is 67.36% (Table 1, Fig. 6a). The movable oil is less than the saturation of the movable fluid, with the main body ranging from 3.5% to 40% (Table 1, Fig. 6c). In general, the correlation between the movable fluid saturation and the porosity is not obvious, even showing negative correlation (Fig. 6a). For example, the porosity of Sample H22-29 is only 1.4% and the movable fluid saturation is 77.76%, while the porosity of Sample H29-16 is 11.1% and the movable fluid saturation is only 67.55% (Table 1). There is a clear contradiction between the data of the movable fluid saturation and the T2 response characteristics (Fig. 5). Therefore, the author believes that the use of saturation for movable fluid evaluation is questionable. Saturation itself is a percentage converted by taking the porosity as the denominator. As a result, although a smaller porosity corresponds to less movable fluid, a larger movable fluid saturation can still be obtained. Therefore, the concept of pore volume of movable fluid is suggested to evaluate the fluid mobility of tight reservoirs. It can be seen from Fig. 5b that the movable fluid porosity has a positive correlation with the porosity. Compared with the movable fluid, the porosity and saturation of movable oil are more positively correlated. The samples with porosity of 5% are the inflection points of movable oil porosity. For samples with porosity less than 5%, the movable oil porosity is generally less than 1%, and the proportion of movable oil in movable fluid is less than 10%. For samples with porosity larger than 5%, the movable oil porosity is generally greater than 1%, up to 3.34%, and the proportion of the movable oil in the movable fluid is generally greater than 20%, up to 53%.
The NMR T2 distribution curve shows that the distribution trend of movable fluids measured by core centrifugation-NMR combined method is the same as that measured by core flooding-NMR combined. With the increase of porosity, the T2 distribution curves gradually change from a single-peak mode to a double- peak mode, and the height and area of the left peak shows an increasing trend (Fig. 7). The larger left peak of the T2 curve, the greater movable fluid can pass through larger pores (Li et al., 2015; Yao and Liu, 2012; Li et al., 2008). The left peak and the right peak are clearly separated, corresponding to Sample A26-15 with a porosity of 9.83%. Compared with A25-05, A24-10, and Z38-01, not only the overall peak area of A26-15 is larger, but also the T2 distribution curves obtained under different centrifugal forces, especially the T2 distribution curves at lower centrifugal forces are more differentiated (Figs. 7d, 7e, 7f).
The movable fluid saturation measured by the method of core centrifugation-NMR combined method is between 7% and 60%, and the movable fluid saturation has a positive correlation with porosity (Fig. 6a). Compared with the results of core flooding- NMR combined method, the movable fluid saturation measured by core centrifugation-NMR combined method is smaller. The poorer the physical properties of the samples, the more obviousdifferences between the results of these two methods show. For example, the porosity of Sample H221-11 is 5%, and the movable fluid saturation measured by core flooding-NMR combined method is 79.58%. The porosity of Sample A23-14 is 5.51%, which has the similar physical property with H221-11, and the movable fluid saturation measured by core flooding-NMR combined method is only 29.63% (Table 1). Comparing with movable fluid saturation, the movable fluid porosity of these two methods shows good consistency. Although the data from the core centrifugation-NMR measurement are generally low, the overall performance is consistent with the porosity (Fig. 6b), which further confirms the rationality of the movable fluid porosity.
Figure 8 shows a histogram of the distribution of movable fluids and throat diameters. In general, the better the reservoir physical property is, the larger the volume of movable fluid controlled by the large throat is. Sample A25-05 has a porosity of 1.62% and a movable fluid saturation of 7.23%. The movable fluid is mainly controlled by the storage space with a throat diameter of 0.1 to 0.2 μm, and the movable fluid saturation in the storage space with throat diameter greater than 1 μm is only 2.6% (Fig. 8a). The porosity of Sample A23-14 is 5.51%, and the movable fluid saturation is 32.32%. The movable fluid is mainly concentrated in the storage space with throat diameter between 0.1 and 1 μm, and the movable fluid saturation in the storage space with throat diameter greater than 1 μm increases slightly, but only 3.1% (Fig. 8b). Sample Z23-01 has a porosity of 8.83% and a movable fluid saturation of 37.64%. The movable fluid is mainly controlled by a storage space with a throat diameter of 0.1 to 1 μm, and a movable fluid saturation in the storage space with throat diameter greater than 1 μm is about 10% (Fig. 8c). When the porosity of the sample exceeds 9%, the movable fluid saturation will increase to 50%–60%. Meanwhile, the storage space of the movable fluid distribution also changes obviously. Most of the movable fluids are distributed in the storage space with throat diameter between 0.2 and 1 μm, in which the movable fluid saturation reaches 30%, accounting for more than 50% of the total movable fluid. At the same time, the proportion of the movable fluid in the reservoir space with throat diameter greater than 1 μm also increases to about 20% (Figs. 8d, 8e, 8f).
Fluid mobility evaluation has become an important issue of the effectiveness evaluation of unconventional tight reservoirs. Compared with the conventional sandstone reservoirs, tight sandstones have smaller pore throats and stronger heterogeneity. Additionally, it is difficult to evaluate its fluid mobility. There are many factors that affect the fluid mobility of tight sandstones, including mineralogy, particle size, diagenesis, and physical properties, as well as subsequent reservoir stimulation, such as acid fracturing, volumetric hydro-fracturing, etc. (Wu et al., 2019b; Li et al., 2015). However, the key factor leading to the difference of fluid mobility is the difference of pore structure. The difference in pore structure will be directly reflected in the physical properties of the reservoir, and the previous works have showed that fluid mobility is directly related to the physical properties; especially it has a good positive correlation with the porosity of the reservoir. In general, porosity ranging from 5% to 8% is the inflection point of pore structure of Chang 7 tight sandstones, and also is the inflection point of the differential distribution of movable fluids. Figure 3 shows the three-dimensional pore structure of samples with different porosity. It can be seen that the samples with porosity greater than 8% have generally more pores and better connectivity than samples with porosity close to 5%. Better connectivity of pore system provides more space for movable fluids. Taking the movable fluid saturation measured by core centrifugation-NMR combined method as an example, the movable fluid saturation of samples with porosity greater than 8% is generally more than 50%, while the movable fluid saturation of samples with porosity less than 5% is generally less than 40%.
In view of the two current methods of movable fluids evaluation in tight sandstones, the results show that the movable fluid saturation measured by core flooding-NMR combined method is generally higher than that measured by core centrifugation-NMR combined method. For samples with similar porosity, the movable fluid saturation data can differ by 10% to 20%, and the smaller the porosity, the greater the difference in movable fluid saturation. The experiment procedure of these two methods is critical to these differences. In this paper, the displacement pressure adopted in core flooding experiment is over 5 MPa, which is larger than the pressure adopted in the core centrifugal experiment (400 psi, about 2.758 MPa). The larger pressure difference can affect the fluid that was controlled by smaller throat, resulting in higher saturation results. In addition, a complete displacement operation was adopted in the core flooding experiment. Taking fluorinated oil displacement of water as an example, the core flooding experiment was ended only after no water was detected at the outlet end and the oil production remained stable, so the overall displacement efficiency is high. The biggest chal-lenge during the core flooding experiments was how to balance the relationship between the injection pressure and the experimental time. The tight sandstone with ultra-low porosity and permeability, was sensitive to large injection pressure which caused rapid breakthrough of fluid in the cores without affecting the pores, and resulted in lower porosity and permeability than actual situation. However, if the injection pressure is too small, the experiment will last several months, which is highly time-consuming. Therefore, to determine the appropriate experiment conditions are key to carrying out successful core flooding experiment, which is still needed for future investigation. In the process of the core centrifuge experiment, it is considered that the long-term rapid rotation of the centrifuge will lead to the rise of temperature, causing fluid evaporation and affecting the results of movable fluid. Therefore, the samples are not completely centrifuged, which is another reason why the movable fluid saturation value measured by core centrifugation-NMR combined method is lower. Moreover, there is only one type of fluid during the centrifugation, and it can't reflect the information of oil and water interaction during the flow, and can only reflect the information of porous structures.
It should be noted that the movable fluid saturation measured by core flooding-NMR combined method brings another problem. In the evaluation of fluid mobility in tight reservoirs, the movable fluid saturation may not be the optimal evaluation index. The movable fluid saturation is only a relative value, which to a large extent cannot reflect the volume of movable fluid in tight sandstone reservoirs accurately. Therefore, it is suggested that the movable fluid porosity should be used to evaluate the mobility of fluid in tight sandstones. It can be seen from Fig. 6 that the movable fluid porosity measured by the two methods is more consistent and comparable.
Generally, the advantage of core flooding-NMR combined method is that this method can be used to evaluate the mobility of different fluids under oil-water two-phase conditions, especially the evaluation of the mobility of oil. The advantage of core centrifugation-NMR combined method is to establish a direct relationship between movable fluid and pore structure, and to realize the fine evaluation of movable fluid in reservoir space controlled by different throats. The combination of the two methods can effectively improve the accuracy of fluid mobility evaluation of tight sandstone.
(1) The lithology of tight sandstones in Chang 7 Member of the Ordos Basin is mainly arkose and feldspar litharenite, with porosity ranging from 2% to 12%. Feldspar-rock fragments dissolution pores, calcite dissolution pores, clay mineral dissolution pores, inter-granular dissolution expansion pores, inter-granular pores, intra-kaolinite pores, and intra-illite/smectite mixed layer pores are developed; 3D CT pore structure shows that the pore connectivity is positively related to physical properties, and the overall storage space is connected by the throat with diameter less than 1 μm, accounting for more than 95%. The diameter of advantageous throat is between 0.2 and 0.3 μm, and its connected volume accounts for 30% of the storage space. The percentage of storage space connected by throats with diameter less than 100 nm can reach more than 35%.
(2) Movable fluid saturation of tight sandstone in Chang 7 Member of the Ordos Basin is between 10% and 70%, and movable oil saturation is between 10% and 50%. There is a good correlation between the porosity of the movable fluid and the physical properties of the reservoir. The porosity ranging from 5% to 8% is the inflection point of the fluidity and pore structure. For samples with porosity less than 8%, the movable fluid saturation is usually less than 40%, and the movable fluid porosity is generally less than 5%. Moreover, the movable fluid is mainly concentrated in the storage space with a throat diameter of 0.1 to 1 μm; For samples with porosity greater than 8%, the movable fluid saturation is generally greater than 50%, and the porosity of the movable fluid is more than 5%, and the movable fluid is mainly concentrated in the storage space with a throat diameter of 0.2 to 2 μm. Movable fluid saturation may cause misunderstanding when used to evaluate fluid mobility, so it is recommended to use movable fluid porosity in the evaluation of fluid mobility.
(3) The movable fluid saturation measured by core flooding-NMR combined method is generally higher than that measured by core centrifugation-NMR combined method. The main reason is that the former uses a larger displacement pressure, resulting in larger fluid displacement efficiency and larger volume. The former can evaluate the mobility of the oil-water two-phase fluid in samples, while the latter can better reflect the pore structure and directly evaluate the movable fluid in the pore system controlled by different throat diameters. In the future, the mobility of fluids in tight sandstone reservoirs can be evaluated by using the above methods according to the purpose of the study, so as to obtain ideal results.
ACKNOWLEDGMENTS: This research was supported by the NSFC (No. 42072187) and CNPC (No. 2019E-26). We express our sincere thanks to Profs. Caineng Zou, Rukai Zhu, and Lianhua Hou for their guidance and constructive suggestions during the research. Ms. Lihua Ding, Ms. Xiaohong Li, Mr. Chao Ren and Mr. Fulin Zhai have provided technical support during the experimental analysis. The final publication is available at Springer via https://doi.org/10.1007/s12583-020-1050-2.| Ao, H., Liu, C. R., Roberts, A. P., et al., 2017. An Updated Age for the Xujiayao Hominin from the Nihewan Basin, North China: Implications for Middle Pleistocene Human Evolution in East Asia. Journal of Human Evolution, 106: 54–65. https://doi.org/10.1016/j.jhevol.2017.01.014 |
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Songtao Wu, Shixiang Li, Xuanjun Yuan, Zhi Yang, Aifen Li, Jingwei Cui, Songqi Pan, Zhiguo Mao, Ling Su, You Zhou. Fluid Mobility Evaluation of Tight Sandstones in Chang 7 Member of Yanchang Formation, Ordos Basin. Journal of Earth Science, 2021, 32(4): 850-862. doi: 10.1007/s12583-020-1050-2
| Sequence | Sample No. | Porosity (%) | Permeability (×10-3 μm2) | Mobility fluid saturation (%) | Mobility fluid porosity (%) | Mobility oil saturation (%) | Mobility oil porosity (%) |
| Core flooding-NMR combined method | H22-29 | 1.4 | 0.007 1 | 77.76 | 1.09 | 4.50 | 0.063 |
| H22-39 | 3.1 | 0.01 | 72.64 | 2.259 | 3.84 | 0.12 | |
| H22-11 | 5 | 0.02 | 79.58 | 3.98 | 4.85 | 0.24 | |
| H31-04 | 5.9 | 0.03 | 52.82 | 3.12 | 17.54 | 1.03 | |
| H22-19 | 6.7 | 0.038 | 66.32 | 4.44 | 21.654 | 1.45 | |
| H29-03 | 7.8 | 0.055 | 60.72 | 4.74 | 5.59 | 0.44 | |
| H22-23 | 8.6 | 0.084 | 72.94 | 6.27 | 38.87 | 3.34 | |
| H29-01 | 9.1 | 0.093 | 62.61 | 5.69 | 9.66 | 0.88 | |
| H29-04 | 9.8 | 0.101 | 63.15 | 6.19 | 11.27 | 1.10 | |
| C25-05 | 10.3 | 0.174 | 69.64 | 7.17 | 28.56 | 2.94 | |
| H29-14 | 10.9 | 0.253 | 62.58 | 6.82 | 13.83 | 1.51 | |
| H29-16 | 11.1 | 0.344 | 67.55 | 7.50 | 18.52 | 2.06 | |
| Average | 7.5 | 0.101 | 67.36 | 4.94 | 14.89 | 1.26 | |
| Core centrifugation-NMR combined method | A25-05 | 1.62 | 0.000 15 | 7.23 | 0.12 | / | / |
| A24-10 | 5.24 | 0.019 | 29.63 | 1.55 | / | / | |
| A23-14 | 5.51 | 0.009 3 | 32.32 | 1.78 | / | / | |
| A24-11 | 6.42 | 0.046 | 25.37 | 1.63 | / | / | |
| A24-12 | 6.54 | 0.10 | 31.65 | 2.07 | / | / | |
| A26-13 | 6.55 | 0.038 | 49.61 | 3.24 | / | / | |
| A24-14 | 6.82 | 0.006 6 | 10.99 | 0.75 | / | / | |
| A23-15 | 6.90 | 0.013 | 26.99 | 1.86 | / | / | |
| Z23-01 | 8.83 | 0.014 | 37.64 | 3.32 | / | / | |
| A26-14 | 8.95 | 0.11 | 60.29 | 5.40 | / | / | |
| A25-06 | 9.23 | 0.017 | 14.05 | 1.30 | / | / | |
| A23-16 | 9.33 | 0.053 | 53.57 | 4.99 | / | / | |
| A26-15 | 9.83 | 0.14 | 53.63 | 5.27 | / | / | |
| Z23-02 | 10.15 | 0.024 | 40.84 | 4.15 | / | / | |
| A26-16 | 10.57 | 0.16 | 57.81 | 6.11 | / | / | |
| Z23-03 | 10.70 | 0.045 | 44.52 | 4.77 | / | / | |
| Average | 7.70 | 0.050 | 36.01 | 3.02 | / | / |
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