Conglomerate oil reservoirs in the Karamay oilfield are mainly distributed in the northwestern margin of the Junggar Basin, and have been produced for 60 years. The Mahu oil reservoir discovered in 2017 is the largest conglomerate oil reservoir in the world. But conglomerate oil reservoirs are complex in pore structure, characterized by low average throat radius, high pore-throat ratio, poor pore connectivity, and massive blind pores and single channel pore networks^[1]. These characteristics result in pre-mature water breakthrough and limited swept area during water flooding, low recovery degree and considerable amounts of remaining oil^[2].

It has been widely acknowledged that surfactant/polymer (SP) flooding can effectively enhance oil recovery of reservoirs after waterflooding^[3]. However, rapid sediment accumulation leads to multi-modal pore structures in conglomerate reservoirs. In a microscopic view, the two-phase fluid flow in cores with different modes presents notable differences, which correspondingly leads to significantly different macroscopic development characteristics from conventional sandstone reservoir. Such differences are especially prominent in SP flooding which involves multiple physicochemical reactions. Therefore, in order to promote the application of SP flooding in conglomerate oil reservoirs, it is of vital importance to investigate effects of pore structure differences on the SP flooding performance.

Many studies have been conducted at the pore scale on the morphology and producing pattern of remaining oil by various methods, including numerical simulation method^[4], microfluidic chip flooding method^[5], pore network model method^[6], ultraviolet fluorescence observation method^[7] and CT scanning method^[8]. These methods to some extent reveal the flow mechanism of multi-phase fluid. However, due to surface property, pore structure, and dimension of different samples, these methods can’t reflect the producing rules of remaining oil in the conglomerate core samples with strong heterogeneity^[9]. The nuclear magnetic resonance (NMR), as a rapid, accurate, nondestructive measurement and testing method, has been widely applied to test the properties of fluids and rocks^[10]. This technique is also used to analyze the remaining oil variation before and after water flooding, gel plugging and chemical displacement in many studies^[11]. But in most cases, the core sample is retrieved from the holder after flooding and then scanned^[12], during which the drive force is gone, and oil and water would re-distribute under the effect of capillary pressure, thereby significantly influencing the experimental accuracy.

Studies on producing pattern of remaining oil at core scale generally conduct oil displacing experiments using cylindrical core samples with diameters of 2.5 cm or 3.8 cm to investigate the displacement characteristics and performances^[13]. But for conglomerate reservoirs, the cross section area of the cored sample is too small to contain large conglomerates existing in the reservoir, and thus the prepared cylindrical core samples are often not representative. Moreover, the pore volume in such cylindrical core samples is too small, and huge experimental errors are found in chemical flooding after water flooding. The full-sized core sample has a diameter up to 10 cm, with sufficient pore volume to overcome the aforementioned problems^[14]. Thus, this paper carries out core flooding experiments on full-hole core samples, in order to truly reflect the effect of pore structure difference on the displacement characteristics.

At present, it is easy to find many available field data regarding the SP flooding in sandstone oil reservoirs, while field testing results of the SP flooding in conglomerate reservoirs are rarely reported. Pilot SP flooding test in the Karamay conglomerate oil reservoir was initiated in July 2010, and high oil recovery was achieved after profile control and well group adjustment. Its production data can be used for comparison of development characteristics of reservoirs with different microscopic pore structures.

To find out the potential of the SP flooding in enhancing oil recovery in different blocks, the effects of pore structure differences on two-phase fluid flow at the pore, core and field scales were investigated respectively. First, the NMR technique was used for in-situ monitoring of the remaining oil variation in pores of different scales to find out the main pore-throat size ranges that oil was produced from during water and surfactant-polymer flooding, respectively. Then, effects of the pore structure difference on core flooding characteristics and oil displacing performances were examined by full-diameter core displacement experiments. Finally, the development characteristics of SP flooding in sandstone reservoir with bimodal pore structure and in conglomerate reservoir with multimodal pore structure were compared to find out the mechanisms enhancing oil recovery. The findings of this research can provide theoretical guidance for oil recovery enhancement in conglomerate reservoirs with various pore structures.

The reservoir pore structure refers to the geometric morphology, size, distribution and connectivity of pores and throats in the reservoir rock. The mode of the pore structure reflects the frequency distribution of the main pore (or throat) sizes. On the basis of thorough research on the packing structure of conglomeratic sandstone, Clarke^[15] proposed the concept of bimodal pore structure and porosity and permeability formulas of the rock with bimodal pore structure. Liu^[16] found that the sandy conglomerate reservoir with poor soring, coarse granularity, and wide range of particle size distribution often had multimodal pore structure. Now, unimodal, bimodal and multimodal pore structures are commonly used to describe the particle distribution and packing pattern of conglomerate core samples, which have certain patterns in pore type and pore-throat association. The cast thin sections, mercury intrusion curves and CT scanning images of core samples collected from wells drilled in the pilot area of the SP flooding in the Karamay conglomerate reservoir were examined to find out the pore-throat association types of different modes of core samples.

The unimodal core sample is relatively well sorted and rounded, with coarse sands as the main grains, and with primary intergranular pores, intergranular dissolved pores, and intragranular dissolved pores as the dominant pore types (Fig. 1). This kind of core sample has abundant pores, large pores and throats connected as networks, low content of cement, most pores and throats unfilled, and high permeability. In general, the unimodal rock presents low threshold capillary pressure (less than 0.01 MPa) and single-peaked pore throat distribution histogram, with the throat radius mainly in the range of 1-10 μm, mean radius of less than 7.5, skewness of -0.94-1.74 (mean 0.45), and even throat distribution. This kind of core has mainly coarse throats, an effective pore connectivity rate of 66.87% and an average pore-throat coordination number of 3.08, indicating good pore throat connectivity. This kind of core includes fine-grained conglomerate, pebbly coarse sandstone, coarse sandstone and medium sandstone.

The bimodal rock consists of grains in two main size ranges, pebble and medium-coarse sand. Pores in the bimodal rock are relatively developed, and dominated by the association of intergranular (intragranular) dissolved pore, primary intergranular pore and matrix pore, with a small amount of cement dissolved pores. Pores in pebble grains are semi-filled or not filled, with developed throats at medium-high level, and are in nearly network or dot distributions (Fig. 2). The capillary pressure curve of bimodal rock features slightly coarse skewness and relatively high threshold pressure (0.03-0.20 MPa). This kind of rock has a main throat radius range of 1-7 μm, mean pore radius of 7.5-9.0, and skewness of -1.28-1.45 (0.24 on average), indicating even throat distribution. Medium throats take dominance in this kind of rock. They have an effective pore connectivity rate of 57.67% and an average pore-throat coordination number of 2.88, indicating good pore throat connectivity. They are mostly pebbly coarse sandstone and sandy conglomerate.

The multimodal rock is formed by grains with three main pore size distribution ranges, respectively corresponding to conglomerate, medium-coarse sand, and silt and mud. Pores in the multimodal rock are poorly developed, and are mainly intergranular (intragranular) dissolved pore, primary intergranular pore and matrix pore, with rare micro-cracks. The pores are usually sparsely scattered, with poor mutual connectivity (Fig. 3) and universal post-diagenetic effect. The capillary pressure curve of this kind of rock is characterized by fine skewness. The pore throat distribution histogram is in unimodal or multimodal types, with high threshold pressure (0.2-0.6 MPa). This kind of rock has a throat radius range of 0.5-9.5 μm, mean pore radius of larger than 9, skewness of -7.26-0.96 (0.22 on average), and uneven throat distribution, with medium to small throats taking dominance. The effective pore connectivity rate of 39.07%, and an average pore-throat coordination number of 2.42, suggesting poor pore throat connectivity. They are mostly sandy conglomerate and muddy pebbly coarse sandstone.

From the unimodal to the multimodal pore structures, the development of pores turns poorer gradually, with pores changing from network distribution with good connectivity to dot distribution with poor connectivity and decreasing in pore- throat coordination number. Although cores of different modes with similar permeability (500×10^-3 μm²) have similar pore throat size distribution range, the pore throat distribution curve of multimodal core presents fine skewness, suggesting more medium-small pore throats and serious microscopic heterogeneity. The typical conglomerate oil reservoir has multimodal pore structure, with high contents of sand and mud, and pebbles suspending in the sand and mud which changing widely in size, resulting in more complex pore structure. Extremely uneven pore-throat size distribution presents multiple peaks and and fine skewness. The differences in the pore structure can result in significant variations in the microscopic pore-throat oil displacement and macroscopic development characteristics between rocks of different modes.

Water: Heavy waters with inorganic salts (with no signal in NMR testing) were used in the NMR testing to ensure that all signals come from oil inside the rock. The ion compositions of water were shown in Table 1.

Chemicals: The KPS-202 anionic surfactant widely used in the Karamay oilfield for SP flooding was adopted in the experiments. To prevent the hydrogen ion in the surfactant aqueous solution from impacting the NMR signal, the surfactant was dried and made into powder. The polymer used in the experiments was polyacrylamide made by the SNF Floerger with a relative molecular weight of 1 900×10⁴ and a hydrolysis degree of 25%-30%. The SP solution used in the experiments had a surfactant concentration of 3 000 mg/L and a polymer concentration of 1 200 mg/L. At the room temperature of 25 °C and shear rate of 7.34 s^-1, the viscosity of the SP solution tested by Brookfield DV-II⁺ was 29 mPa•s. The interfacial tension between the crude oil and SP solution measured by TX500 spinning drop interface tensiometer at 25 °C at the spinning velocity of 5 000 r/min was 8×10^-3 mN/m.Oil: Crude oil used in the experiments was collected from the production well and degassed, which had a viscosity of 38 mPa•s at 25 ºC. The composition of the crude oil is given in Table 2.

Core: Based on the analysis results of cast thin sections, full diameter core samples able to represent unimodal, bimodal and multimodal pore structures were selected from cores from Xinjiang Oilfield to do core flooding experiments. Since natural full diameter core samples are not homogeneous porous media and their cross-sectional areas are larger than the fluid flow seepage area, it is not possible to obtain the permeability of full diameter cores by conventional permeability measurement methods. Instead, the permeability of drilled cylindrical core plugs from full diameter core samples were measured as replacement. Therefore, three cylindrical core plugs of 2.5 cm in diameter (Fig. 4) were drilled from the full diameter core samples to do in-situ NMR tests. The mineral composition of the three small cylindrical core plugs was measured by the X-ray diffraction test, and presented in Table 3.

2.2.1. Apparatus

Low frequency nuclear magnetic resonance spectrometer (MarcoMR) was used to perform NMR in-situ displacement experiments. The core sample is placed in a holder that is made of non-magnetic materials and installed in the NMR apparatus. In this way, the redistribution of oil and water induced by capillary pressure can be eliminated when taking out the core sample from holder. The diameter of the full diameter core sample holder is 10 cm, and the largest holding length is 1.0 m. The holder can measure the pressure, liquid production in real time, with the highest pressure of 50 MPa and temperature of 150 °C.

2.2.2. Methods

In the flooding experiment of the core plugs, the pump rate was set at 0.06 mL/min, the corresponding flow rates are 0.83, 0.89 and 0.92 m/d in the reservoir for the three core plugs. The three core plugs were respectively vacuumed and saturated with the heavy water. Then, they were flooded by oil to reach the irreducible water saturation, and aged for one week before put into the NMR in-situ displacement system. During the NMR-assisted core flooding test, the core plug was first flooded by heavy water until no oil was produced, and then the SP solution was continuously injected until no more oil was produced (i.e. the signal amplitude of the relaxation time T₂ had no considerable variation). The variations of remaining oil in all kinds of pores were calculated based on the magnitude of the signal amplitude variation^[17].

In the flooding experiments of full diameter core samples, the migration rate of simulated fluid in reservoir was set at 1 mL/min, the corresponidng pumping rates are 1.15, 1.02 and 0.91 mL/min in the reservoir for the three cases. The experimental procedure is as follows: (1) The full diameter core sample was placed in the full diameter core holder, vacuumed and saturated with water, and its porosity was calculated. (2)The core sample was displaced with oil to reach irreducible water saturation. (3) The core sample was then flooded with water to the water cut of 90%, 0.1 PV of the polymer slug was injected, followed by 0.3 PV of the SP slug and 0.1 PV of the polymer protection slug. Afterwards, the core sample was flooded with water until the water cut reached 98%. The pressure, oil production and water production during the whole process were continuously monitored.

The oil displacement efficiencies in the 3 core plugs with different pore structures were calculated with the cumulative decline amplitude of the NMR signal and the produced oil quantity, the results are shown in Table 4. It can be seen that the ultimate oil recovery calculated by the two methods are basically consistent, indicating that the calculation result from signal energy spectrum is reliable. As the oil saturating the core sample was only 4-5 mL, it is difficult to measure the dynamic data in different displacement stages with the conventional metering device accurately. Given this, the oil displacement efficiencies in different types of pore-throats in different stages were calculated by using the cumulative signal decline amplitude of the relaxation time T₂.

Oil displacement experiment results of the three core plugs are listed in Fig. 4 and Table 5. The bimodal and multimodal core plugs had similar oil recovery of 28.4% and 28.0% respectively in water flooding stage. But they differ some in oil recovery by SP flooding, the bimodal core plug had an oil recovery increment of 26.9%, slightly higher than that of the multimodal core plug of 25.8%. The unimodal core had the highest oil recovery efficiency during the water flooding and the highest ultimate oil recovery after SP flooding, but the lowest incremental recovery degree of SP flooding of 21.8%. As the unimodal core plug has simpler pore structure and better sorting, it is easier for water to sweep the pores in it despite its lowest permeability, so it had the highest oil displacement efficiency. As for the bimodal and multimodal core plugs, the presence of large pebbles aggravates the microscopic heterogeneity of them, and the oil inside tiny pores is hard to be displaced by water, due to the large capillary pressure. The application of SP flooding resulted in the highest producing degree of remaining oil in the bimodal core plug, and the lowest in the unimodal core plug. This is because the water flooding oil recovery of the unimodal core plug was the highest, and there was little remaining oil left for the SP flooding. Furthermore, the multimodal core plug has the most complex pore structure, and the tortuous and long pore throats in it restricted the production of remaining oil during SP flooding stage.

The pressure and oil recovery degree curves of the three core plugs with different pore structures are shown in Fig. 5. Their injection pressures had no significant differences during the water flooding stage, and were around 0.03-0.04 MPa. But the injection pressure of the multimodal core plug was significantly lower than that of unimodal and bimodal core plugs during the SP flooding stage, that is because the bimodal core plug has larger permeability than the other two. Moreover, the tortuous throats of the multimodal core produced stronger shear to the polymer, resulting in lower viscosity of the polymer solution in this core plug than in the other two^[18].

The relaxation time T₂ of the NMR can be converted into pore radius based on the conversion coefficients of cores with different lithologies^[17]. The variations of fluid signal amplitude in the pores of the three core plugs with different pore structures after water flooding and SP flooding are presented in Fig. 6. Since no signal is emitted by the heavy water, the fluid signal of pore after oil saturation should be from oil. The signal amplitude curve of the single-phase fluid can reflect the pore structure characteristics (as shown by the red curve in Fig. 6). Although the three core plugs have little difference in permeability, they differ obviously in pore size distribution. With the increase of pebble content, the proportion of small pores increases. The fluid contained in pores with radius smaller than 1.0 μm in the bimodal core plug is much more than that in the unimodal core. For the multimodal core plug, the fluid signal amplitude peak is present at the pore radius of 1 μm and the pore distribution is bimodal on the whole.

The contribution of oil recovered from different pore sizes to the total oil recovery was calculated by using the fluid signal amplitude variations in pores of different sizes grades, as shown in Table 5. In water flooding, oil recovered from grade II, III and IV pores in the unimodal core plug all contribute more than 25% to the total oil recovery. In contrast, for the other two core plugs, the displacing phase fluid is hard to get into the grade I, II, and III pores, and the oil displaced out from the grade IV pores apparently contribute more to the total oil recovery than that from the other grades of pores. During the SP flooding, in the unimodal core plug, the contribution of oil recovered from the grade II pores increases than that in water flooding. For the bimodal and multimodal core plugs, the SP solution still mainly displaces remaining oil inside grade IV pores, and hardly displaces remaining oil in grade I and II pores.

It is worth mentioning that instead of declining, the remaining oil in the grade I pores of the multimodal core plug increased during water flooding. This is because the NMR method inverses the pore size from fluid content, and the pore size from this method is in fact the size of the remaining oil cluster. Owing to the complex pore structure in the multimodal cylindrical core, oil in grade II, III and IV pores is displaced and dispersed, adsorbing in the form of oil film and oil cluster on the pore surface or remaining in the pore corner, so small-sized oil clusters increase in number, which is shown as increase of remaining oil in grade 1 pores. Then during the SP flooding, the mobility control and ultra-low oil/water interfacial tension of the SP system can remove the oil film absorbed on pore surface and make oil clusters gather effectively. This is embodied as significant decline of remaining oil in grade I pores on NMR spectrum.

The relative recovery degrees of oil in different grades of pores in the core plugs of 3 modal pore structures are shown in Fig. 7. The relative recovery degree denotes the producing degree of oil in pores of different grades during flooding. As the pore structure gets more complex, the producing degrees of grade I, II and Ⅲ pores in water flooding get lower. In the SP flooding, the relative recovery degrees from grade II pores of the unimodal and bimodal core plugs grow larger than those in grade III pores (Fig. 7d, 7e), which indicates that the remaining oil in grade II pores is more easily displaced. In the multimodal core plug, the recovery degree of grade II pores grows in smaller magnitude than that of grade III pores, which indicates the strong heterogeneity of the multimodal core makes it difficult even for the SP solution to displace the remaining oil in grade II pores out.

The pore structures of the three full diameter core samples were first tested by NMR, as shown in Fig. 8. It can be seen that the pebbly coarse sandstone (bimodal) and the sandy conglomerate (multimodal) both present double-peaked pore distribution. The bimodal core sample has a higher proportion of large pores than the multimodal core sample, but the multimodal core has larger maximum pore radius and larger pore radius corresponding to the peak of pore distribution than the bimodal core. The medium sandstone (unimodal) has fairly even pore size, and an average pore radius much smaller than the other two types of cores. By comparing the red curves in Figs. 6 and 8, it is found out that the pore size distributions of the full-diameter bimodal and multimodal cores are greatly different from those of the corresponding small core plugs, while the pore-throat distributions of the unimodal full diameter core and small core plug are consistent largely. This suggests the full diameter core samples can reflect the microscopic heterogeneity of pore-throat distribution and the effects of macroscopic pores and micro-fissures.

The flooding test results of the three full diameter core samples are presented in Table 6. The unimodal core is highest in water flooding efficiency, the multimodal core is lowest. Moreover, as the content of pebble increases, water is easier to break through, the water-free production period gets shorter, and the efficiency of water displacing oil gets lower. In the chemical flooding and post-water flooding, the multimodal core sample has the highest increase of recovery degree, and the unimodal medium sandstone is the lowest. But in terms of total oil recovery, the unimodal medium sandstone still is the highest, while the multimodal sandy conglomerate core sample is the lowest. Comparing results of the core flooding with those of the columnar core plug flooding (Table 4) shows that the flooding results at different scales have both similarities and difference. The similarities are: the unimodal core plugs have the highest recovery degree in the water flooding stage and lowest recovery degree growth in the chemical flooding stage. The difference is that the multimodal full-diameter core has higher recovery degree increase in chemical flooding than the bimodal full-diameter core plugs. This is because that in the full diameter core flooding test, it was hard for water to displace oil in the multimodal full-diameter core with stronger heterogeneity, and thus more movable remaining oil was left behind for chemical flooding after water flooding; while in the flooding test of the columnar core plugs, due to the small core size, the heterogeneity difference between the bimodal and multimodal core plugs was not obvious enough to result in significant gaps between the recovery degrees of water flooding and chemical flooding. The comparison of oil displacing results of cores at the two scales demonstrates that the full diameter core can not only reflect the heterogeneity difference but also the displacement characteristics of different modal cores.

The recovery degree and water cut curves of the three full-diameter core samples in Fig. 9 show that the recovery degree of the unimodal core sample goes up rapidly during the water flooding, rising up slowly during the chemical flooding, and then rises fast in the subsequent water flooding. The possible reason is the unimodal core sample has small pores and throats, although the polymer of the SP system matches with most pore throats in the core, it is still unable to enter the small pores to displace oil effectively. The polymer has selective plugging in the relative homogeneous unimodal core sample, making the subsequent injected water enter into smaller pores to enhance oil recovery. The bimodal and multimodal core samples have similar recovery degree curves. In the water flooding, the recovery degree of the bimodal core sample is slightly higher than that of the multimodal core sample. In the chemical flooding stage, both curves have an obvious upwarp, while the recovery degree of the multimodal core sample goes up faster than that of the bimodal one, and finally the two curves get close to each other.

In the chemical flooding stage, both the water cut curves of the bimodal and multimodal core samples have an apparent V-shaped section. The water cut of the multimodal core dropped to the lowest of 33%, while that of the bimodal core to 69%; the water cut of the unimodal core sample kept at around 90% during the SP flooding, and only dropped to 85% at the end of SP flooding. But the water cut curve of the unimodal core sample has a short-lived V-shaped section in the subsequent water flooding, with the water cut dropping to the lowest of 75%.

The fluids produced from the multimodal and unimodal core samples during the chemical flooding are shown in Fig. 10. It can be seen that the oil in the multimodal core sample had emulsion in the SP flooding stage, which lasted till the subsequent water flooding stage; while the oil in the unimodal core sample had no emulsion during the whole SP flooding. This is because the large and tiny pores in the multimodal core sample connect in complex ways, when the oil and SP solution enter tiny pore channels from large pore channels, they are blocked and the oil is dispersed, and the surfactant in the chemical system can keep the oil drops dispersing in the water phase until it is produced. In contrast, the unimodal core sample has simpler pore structure, so oil and water in this sample aren’t likely to cut off due to drastic variation of the flow channel. In addition, the unimodal core has smaller grain size and thus larger specific area. In such case, the surfactant tends to adsorb onto the grain surface, which is unfavorable for the emulsion process.

The injection pressure curves of the three full diameter core samples during the whole flooding process are shown in Fig. 11. The displacement pressure of the multimodal sandy conglomerate is much lower than those of the bimodal and unimodal cores, and at the late stage of the water flooding, it was only about 4 kPa. Combined with the corresponding water cut curve, it is found that serious channeling happened in this core during water flooding. Its displacement pressure rose rapidly to 50 kPa after injection of the polymer slug, which is 12.5 times of that in the late stage of water flooding. The injection pressure then started to decline through the SP flooding stage, due to the drop of interfacial tension and constantly reduction of remaining oil. But it remained at about 40 kPa at the end of the SP flooding, which is 10 times of the injection pressure at the late stage of water flooding. In the subsequent water flooding, the injection pressure dropped quickly, and stabilized at 7 kPa. For the bimodal core sample, the injection pressure rose rapidly first and then dropped slowly as the water injection proceeded, and yet was up to 170 kPa at the end of this stage; the injection pressure during the SP flooding first rose to the peak and then slowly fell, but at the end of SP flooding, it was still 3 times of that at the end of water flooding. The injection pressure was 249 kPa at the end of subsequent water flooding. Since the unimodal core sample used in the experiment is small in pore radius, its injection pressures during both the water flooding and chemical flooding were very high, was stable near the end of the water flooding, and went up constantly during the chemical flooding, to 1.5 times of that in the water flooding at maximum.

The core plugs drilled from the full diameter core samples with three different types of pore structures have similar permeability, but the displacement pressures of the three full diameter core samples are greatly different. This is because that the core plugs drilled from the bimodal and multimodal core samples can’t contain large size pebbles, while there are usually pebble boundary fractures or micro cracks at the cemented bond between pebble and sand, which can lead to channeling during the displacement process. This feature can be better reflected by the flooding experiment on full diameter core sample.

Block A in Liaohe Oilfield is a typical reservoir with bimodal pore structure, with an average effective permeability of 750×10^-3 μm², reservoir temperature of 55.0 ºC, formation water salinity of 2 467 mg/L, and crude oil viscosity of 14.3 mPa•s at 55.0 ºC. The target interval has an effective thickness of 13.6 m on average, and original oil in place (OIIP) of 298×10⁴ t. The five-spot well pattern at well spacing of 150 m was used before SP flooding. There are 59 wells, among which 24 are injection wells and 35 are production wells. The recovery degree in water flooding stage was 46.3%. In the chemical flooding stage, the polymer with relative molecular weight of 3 000×10⁴ was used. The prepad slug was a polymer solution with a concentration of 2 500 mg/L and the injection amount was 0.1 PV. The main slug was a SP solution made up of a polymer solution with a concentration of 2 000 mg/L and a surfactant with a concentration of 0.4%, and the injection volume was 0.65 PV. Subsequently, 0.2 PV of a vice SP slug with the same polymer concentration as the main slug and surfactant concentration of 0.3% was injected. Eventually, a protective slug of polymer solution with a concentration of 1 400 mg/L of 0.1 PV was injected. The total fluid volume injected was 1.05 PV and the injection rate was 0.15 PV/a.

In the SP flooding stage, the daily oil production increased sharply from 67 t to 320 t, the total water cut reduced from 96.7% to 82.8%, and the displaced reservoir thickness ratio increased from 60.6% to 85.1%. The pilot had a long low water cut period, and the water cut began to rise when the 0.4 PV of SP solution was injected, which is higher than the 0.2 PV in the conventional SP flooding. The recovery degree increased by 18%, which is 2.5% higher than the predicted value (15.5%).

Block B in Xinjiang Oilfield is a typical reservoir with multimodal pore structure primarily composed of anisometric sandy conglomerate and medium-fine sandstone, with a porosity of 18.0% and permeability of 94×10^-3 μm². The reservoir temperature is 40.0 ºC, and the formation water salinity is 13 700 mg/L-14 800 mg/L. The crude oil is 17.85 mPa•s in viscosity at 40.0 ºC, with the acid number of 0.2-0.9 mg/g. The target interval has an average effective thickness of 11.6 m and original oil volume in place of 120.8×10⁴ t. The five-spot well pattern with well spacing of 150 m was used before SP flooding. There are totally 55 wells, among which 29 are water injection wells and 26 are oil production wells. At the end of the water flooding (June, 2010), the comprehensive water cut amounted to 95.0%, and the recovery degree reached 42.9%.

The reservoir physical properties in the pilot is changing fast, and fluid channeling was serious at the late stage of water flooding. In the initial stage of SP flooding, HPAM with relative molecular weight of 2 500×10⁴ was used in the pilot as the mobility control agent. As the test went on, many wells dropped significantly in liquid production, associated with uneven formation pressure distribution. Following the guiding idea of match between polymer and pore and mobility control, the formulation was adjusted for four times. The molecular weight of the polymer in the primary slug dropped from 2 500×10⁴ to 1 500×10⁴ and at last to 1 000×10⁴; the viscosity of the polymer solution fell from 60 mPa•s to 30 mPa•s, 15 mPa•s and 10 mPa•s finally; the injection rate decreased from the initial 0.12 PV per year to 0.1 PV per year. Moreover, the southern part of the pilot with relatively poor physical properties was shifted to water flooding stage, while a well group with 8 injection wells and 13 production wells in northern part of the pilot with good physical properties and abundant remaining oil was developed by the SP flooding continuously.

The SP flooding test was initiated in July 2010 in B block, which had issues such as low liquid production of individual wells, premature chemical breakthrough and high content of SP in the produced fluid and uneven formation pressures. Consequently, the test result was not satisfactory. After the adjustment of formulation and well groups, liquid production declined reasonably with dramatic decline of water cut. The prepad slug adopted polymer with high molecular weight and high concentration to recover remaining oil in the high permeability zone and gradually block high permeability channels. At this stage, the liquid production decreased significantly, whereas the water cut dropped not much. In the SP main slug stage, SP solution of polymer with medium molecular weight and high concentration and surfactant with high emulsification ability was injected, which combined with fracturing and adjustment of injection-production scheme, aimed to displace oil in the medium-high permeability zone and further enlarge the swept volume. In the late stage of SP flooding, on the premise that the high permeability layer still maintained high resistance, medium concentration polymer solution with medium molecular weight and low interfacial tension surfactant with moderate emulsification ability were employed to displace oil in the medium and low permeability zones. The effect of the SP flooding over the whole pilot area peaked in November 2015 and sustained. The pilot had stable liquid production, with the daily oil production rising from 14.7 t at the end of water flooding to 54.6 t, and water cut reducing from 86.6% at the end of water flooding to 56.1%, by over 30%, as shown in Fig. 12. By June 2018, the cumulative injected SP solution in the pilot area amounted to 0.6 PV, accounting for 76.9% of the designed injection quantity, and the water cut remained low. Since the chemical injection starting in July 2010, the pilot had produced 12.7×10⁴ t of oil cumulatively, with a periodic recovery degree of 23.6%. Specifically, the recovery degree during the SP flooding was 15.6%, and it is expected to reach 18% by the end of the SP flooding.

The sandstone reservoir mainly with unimodal or bimodal pore structure and the conglomerate reservoir mainly with multimodal pore structure differ obviously in SP flooding characteristics. For the SP flooding in the sandstone reservoir, the injection rate is usually 0.12a-0.18 PV/a, while the SP slug volume injected is usually 0.4-0.7 PV; the oil production often peaks at the injection of about 0.3 PV; and the water cut starts to rise at the injection volume of about 0.4-0.5 PV^[19]. Quite different from sandstone reservoir, the SP flooding in the conglomerate reservoir with multimodal features continuous drop of water cut and liquid production at large magnitude, the low water cut last after injecting 0.6 PV of the SP solution. Due to the strong microscopic and macroscopic heterogeneity of the conglomerate reservoir, the early injected polymer system with high molecular weight and high concentration as well as scaled profile control and multi-round profile control for typical wells plugged the large flow channels effectively. In the subsequent injection stage, the molecular weight and concentration of the polymer system were reduced, in order to better sweep the mediu-tiny pores and low-permea-bility zone. This injection program involving stepwise concentration reduction has obtained good effect.

However, there are still huge challenges for the application of chemical flooding in conglomerate reservoirs. The production data of typical wells of SP flooding and adjacent polymer flooding pilots are shown in Figs. 13 and 14, respectively. Although these two pilots have similar reservoirs of multimodal sandy conglomerate, the polymer flooding pilot has an average reservoir permeability of 458×10^-3 μm² (five times of that in the SP flooding pilot B), and a well space of 125 m, which is smaller than block B. It can be seen from the figures that the water cut and liquid production in block B decline significantly, while no obvious breakthrough characteristics of the polymer flooding in sandstone reservoir with polymer flooding. It is inferred that the multimodal conglomerate reservoir with higher permeability is also more prone to channeling, and the small well space aggravates channeling further. Although the profile-control slug composed of polymer with high molecular weight and concentration and gel was injected in the early stage, no apparent effect has been achieved. Therefore, to enhance oil recovery of multimodal conglomerate reservoir by chemical flooding, the early profile control and optimization of well space must be done well.

From the reservoir with the unimodal pore structure to reservoir with the multimodal pore structure, the pores decrease in number, turn from the networked distribution with good connectivity into dotted distribution with inferior connectivity, and reduce in connectivity and pore-throat coordination number.

Compared with water flooding, SP flooding can significantly mobilize remaining oil in 1-3 μm pores of unimodal and bimodal core samples. But for the multimodal core sample, SP flooding mainly displaces remaining oil in pores greater than 3 μm in radius.

The unimodal core sample has the highest oil displacement efficiency while the multimodal core sample has the lowest by water flooding. The injection of SP solution in the multimodal core sample can make the displacement pressure increase and remaining oil emulsify, thus enhancing swept volume and consequently oil recovery substantially. In contrast, emulsion wouldn’t happen in the SP flooding of unimodal sandstone.

Compared with sandstone reservoir, the multimodal conglomerate reservoir is more prone to channeling. Besides plugging macroscopic channels with high-permeability, the low swept volume caused by the microscopic pore structure difference must be solved to get good effect of chemical flooding.