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Article

Evaluation of Reservoir Damage by Hydrothermal Fluid from Clay Metamorphism, Particle Migration, and Heavy-Component Deposition in Offshore Heavy Oilfields

by
Zuhao Zheng
1,*,
Lu Zhang
1,
Hongchao Yin
1,
Dong Liu
2,
Wei He
1,
Leilei Shui
1,
Ning Wang
1,
Hao Chen
3,
Shenglai Yang
3 and
Yiqi Zhang
3,*
1
EnerTech-Drilling & Production Co., China National Offshore Oil Corporation, Tianjin 300452, China
2
China National Offshore Oil Corporation Tianjin Branch, Tianjin 300452, China
3
National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing), Beijing 102249, China
*
Authors to whom correspondence should be addressed.
Processes 2024, 12(9), 1959; https://doi.org/10.3390/pr12091959
Submission received: 19 July 2024 / Revised: 25 August 2024 / Accepted: 9 September 2024 / Published: 12 September 2024
(This article belongs to the Section Energy Systems)
Browse Figures
Versions Notes

Abstract

:
Marine heavy-oil reserves are enormous, and thermal recovery technology is one of the most effective ways to utilize them. However, steam as a high-energy external fluid will affect the geological characteristics of the reservoir. In this paper, the sensitivity of the reservoir was analyzed in terms of the high-temperature metamorphic characteristics of clay minerals and the coupling damage of particle migration and heavy component deposition. Firstly, long-core cyclic steam stimulation experiments were conducted using supersaturated steam, saturated steam, and superheated steam to quantify the differences in oil recovery capabilities. Subsequently, the variation characteristics of clay components in the core under different steam temperatures were analyzed by X-ray diffraction spectroscopy. Finally, the influence of particle migration and heavy-component deposition on reservoir permeability was clarified through displacement experiments. The results show that the recovery of superheated steam is more than 12% higher than that of supersaturated steam, and the throughput cycle is effectively shortened. In the laboratory, only the clay metamorphism due to superheated steam was more effective, and the metamorphism was mainly concentrated in kaolinite and monazite. Particle migration causes little damage to the reservoir, but the formation of particle migration coupled with heavy-component deposition can lead to more than 30% of the reservoir becoming damaged.

1. Introduction

The resources of the oceans are enormous, and how to utilize them scientifically and efficiently has always been the subject of unremitting exploration by scientists [1,2]. Therefore, more and more petroleum engineers began to devote themselves to the research of efficient offshore oil development technology [3,4]. Currently, with the continuous development of technology, the proportion of offshore oil extraction is increasing [5]. Taking China as an example, according to the statistics of the National Energy Administration of China, the total output of offshore oil in 2023 exceeded 62 million tons, accounting for more than 60% of China’s oil production increase for four consecutive years. Thereby, it is important to find ways to further increase and stabilize the production of marine oil, which will help to alleviate the world energy crisis.
Due to the particularity of the marine environment and its higher investment costs, offshore oil development inevitably faces the problems of large-well spacing, high injection–production intensity, and the high viscosity of crude oil and needs to obtain higher recovery results than onshore [6,7]. This poses a huge challenge to oil development technology. Dong [8], Huang [9], and Allahyarzadeh-Bidgoli [10] indicated that the thermal recovery technique may become the primary option to unlock highly viscous offshore heavy-oil reservoirs.
Thermal recovery technology has a wide range of applications and a long history of application [11,12]. Heavy oil has greater viscosity and poorer fluidity due to its higher levels of gums and asphaltenes [13,14]. Meanwhile, the unstable structure of heavy macromolecules also gives heavy oil stronger thermal sensitivity [15]. Therefore, thermal-recovery technology has become the preferred development plan for most heavy-oil fields due to its strong applicability and simple operation. Zhang [16] and Xu [17] confirmed through experiments that the reduction of heavy-oil viscosity under heat, volume expansion, distillation, and pyrolysis at high temperature were the main mechanisms of thermal recovery to improve heavy-oil recovery. Among the thermal-recovery methods, steam-cycle stimulation is often applied in the early stage of the development of heavy-oil reservoirs and has been successfully applied in oilfields such as Liaohe [18], Shengli [19], and Emeraude [20]. However, field application also exposed the limitations of steam-cycle stimulation, such as the increasing water content and rapid decreasing in oil production in the later stage, which further reduces its economic feasibility in the development of offshore heavy-oil reservoirs [21,22,23]. Thereby, how to improve the conventional steam-cycle-stimulation method to further explore the reservoir development potential has become an important issue to be solved in the development of offshore heavy-oil reservoirs.
The development effect of steam-cycle stimulation can be improved fundamentally by improving the injection medium. At present, the injection medium of steam is mostly saturated steam with certain dryness. Compared with it, superheated steam has a higher energy and temperature and stronger diffusion and heat transfer capacities, so it has been focused on by scholars [24,25,26]. Sun [27] proposed a new model for calculating the heating radius and analyzing the production performance of circulating superheated steam stimulation wells. Yao [28] proposed a new model to predict the thermophysical properties of superheated steam in injection wells and for estimating wellbore thermal efficiency. Xu [29] evaluated superheated steam from mathematical models and numerical simulation research. Zhang [16] investigated the effect of superheated steam on seepage capacity and actual harvesting by indoor physical experiment and CT technology. These studies clarified the effect and mechanism of superheated steam extraction, but neglected the effect of high-temperature and high-pressure injected fluids on formation minerals. The instability of clay minerals makes them susceptible to change at high temperatures and pressures, so the injection of superheated steam will affect the mineralogical composition of the reservoir, but the actual extent and results of the effect are still unknown [30,31,32]. At the same time, the gaseous characteristics of superheated steam makes it transport more formation particles at high injection rates. These particles are bound to adsorb and precipitate in the formation full of asphaltenes and colloids, thus blocking the formation pore throat and causing pollution, but the extent and weight of the impact is not yet conclusive [33,34]. He [35] focused on the variation mechanism of montmorillonite in cyclic steam stimulation. Liu [36] combined molecular dynamics with heat recovery experiments to investigate the interaction mechanism of minerals and oil. More and more scholars have been paying attention to these scientific problems.
In order to solve the above scientific issues, this paper takes the Lvda Oilfield as the research object, which is the first large-scale thermal recovery of ultra-thick oilfields in China’s offshore [37,38]. Firstly, the 3D scaling long-core cyclic steam stimulation experiments were implemented, and the production characteristics of supersaturated steam, saturated steam, and superheated steam were analyzed. Afterwards, the influence of different steam on the metamorphism of clay minerals was analyzed by X-ray diffraction. Finally, the extent of damage to the reservoir after the depositional coupling of formation particles and heavy fractions was analyzed by displacement experiments.

2. Experimental Setup and Methodology

2.1. Materials

The cores used in the experiments were provided by the Lvda Oilfield in China. Because the rock samples are very loose, the process of freeze-sampling was used to maintain the consolidated state of the cores. Afterwards, the core was sealed with a tin plug net for consolidation protection and transported to the laboratory to wash oil. A basic physical property analysis of the core was conducted, and the results are listed in Table 1. The three long cores were taken from adjacent locations and used for steam-cycle stimulation experiments; the four short cores were used for velocity sensitivity experiments.
Heavy-oil samples were collected from the Lvda Oilfield in China. The viscosity of degassed heavy oil is 63,220 mpa·s−1, and the density is 0.9687 g/mL at atmospheric pressure, 20 °C temperature, and 170 s shear rate. The API of the oil at 15.6 °C was 12.48. The average contents of saturated and aromatic hydrocarbon, resin, and asphaltene in heavy oil are 68.68, 25.31%, and 6.01%, respectively. The water sample used in the experiment was simulated formation water, and the total mineralization of the water was 22,583.26 mg/L, pH = 7.48.

2.2. Steam-Cycle Stimulation Experiment

The steam used in this work was produced by heating distilled water in a supercritical steam generator (U-ZQ-450, Jiangsu-Lianyou Scientific Research Instrument Co., Jiangsu, China). The rated steam pressure of the equipment is 0~55 MPa (0.1 MPa), and the rated steam temperature is 450 °C (±0.5 °C). In order to simulate a more realistic injection environment, the experiment was designed according to the similarity criterion, and 3D scaling was performed on the actual working condition parameters in the field to obtain the injection parameters in the experiment [39]. The injection parameters in the experiment are listed in Table 2.
The specific steps in the experiment are as follows: (1) The experimental platform was built according to Figure 1, and the air tightness was checked. (2) The core was placed in the long-core holder and vacuumed for 6 h. (3) The simulated formation water was injected into the core at a rate of 0.2 mL/min, and the initial irreducible water saturation was measured. (4) The oil was injected into the core at a rate of 0.2 mL/min, and injection of 1 PV oil was continued when no water was produced to ensure full saturation. The initial oil saturation and irreducible water saturation were measured. (5) The core was aged in an incubator at formation temperature for more than 48 h to restore the initial wetting state of the core. (6) Steam-cycle stimulation (SCS) experiments were conducted according to experimental parameters in Table 2. First of all, the distilled water was pumped into a steam generator and heated to the experimental temperature. When stable steam was produced, it was injected into the core holder, and the well was shut down. (7) After the preset shutdown time was reached, the well was opened at 4 MPa back pressure for depletion production. The discharged liquid was collected, and the temperature, pressure difference, and oil production were recorded. The above steps were repeated until 6 cycles had been completed.

2.3. Clay Mineral Component Determination Experiment

The Bruker D8 Discover X-ray diffractometer was used for the X-ray diffraction analysis of clay minerals with a maximum power of 3 kW. The analysis results were processed by Jade software (9.0, Materials Data, USA); full spectrum fitting, the Rietveld method, and map fitting were performed. Before the SCS experiment, the core was sampled as the initial control group. After the SCS experiment, samples were taken at the same position as the experimental group. The clay minerals in sandstone were extracted, the samples were crushed to a particle size of less than 5 mm, and the oil-bearing sandstone was extracted to less than fluorescence level IV using trichloromethane. The crushed samples were soaked in distilled water and dispersed by ultrasonic waves. The clay suspensions with particle sizes of less than 2 μm were absorbed to prepare naturally oriented sheets for X-ray diffraction analysis. The X-ray diffraction (XRD) spectra were obtained for oriented slides from 5° to 70° in 2 theta and increments of 0.0205°.

2.4. Water Flooding Experiment

Water flooding experiments were used to determine the velocity sensitivity of offshore heavy-oil reservoirs and analyze the damage caused by particle migration and coupled deposition of heavy components. The first part of the experiment was to water-flood natural cores to determine the velocity sensitivity of offshore heavy-oil reservoirs with different permeability and to collect fluids containing formation particles. The experiment was carried out in accordance with Chinese oil and gas industry standard SY_T 5358-2010 <Experimental Evaluation Method for Reservoir Sensitivity Flow>, and the core parameters are shown in Table 1. The steps were as follows: 1. The simulated formation water was configured as the speed-sensitive experimental fluid. 2. The core was dried and its dry weight measured. The core was then saturated with formation water. 3. The core was loaded into the holder, the confining pressure was adjusted to 2 MPa, and the confining pressure was always higher than the inlet pressure of 2 MPa in the subsequent experiment. 4. The formation water was used to displace the core with a flow rate of 0.1. When the pressure at the injection end was stable, the pressure at the injection end was recorded. After the flow rate was stable, the flow rate at the outlet end was recorded. 5. The flow rate was increased to 0.25 cm3/min, 0.5 cm3/min, 0.75 cm3/min, 1 cm3/min, 1.5 cm3/min, 2 cm3/min, 3 cm3/min, 4 cm3/min, 5 cm3/min, and 6 cm3/min. Step 4 was repeated. The pressure at the injection end and the amount of liquid out of the outlet end were recorded. 6. The core’s permeability was calculated according to the Darcy Formula (1), and the permeability change rate was calculated according to Formula (2).
K 1 = μ · L · Q ∆ P · A × 10 2
D v n = K n − K i K i
The second part of the experiment analyzed the damage caused to the reservoir by particle migration and heavy-component coupling deposition. It used fluids containing formation particles to displace the cores after SCS experiments. The steps were as follows: 1. The core at 1/2 position and at the end of the supersaturated steam experiment, the core at the end of the saturated steam experiment, the core at the end of the superheated steam experiment, and the core, five cores in total. Permeability was measured by displacement of simulated formation water and formation water containing formation particles. 2. The simulated formation water was the control fluid. The expulsion fluid in the velocity sensitivity experiment described in Section 2.4 was the experimental fluid. 3. The core was dried and the dry weight determined. The cores were saturated with formation water. 4. The core was loaded into the holder, the confining pressure was adjusted to 2 MPa, and the confining pressure was always higher than the inlet pressure of 2 MPa in the subsequent experiment. 5. The core was displaced using formation water and collected rate-sensitive test expulsion fluid at a flow rate of 0.2 cm3/min. The pressure at the injection end was recorded when the pressure at the injection end stabilized, and the flow rate at the exit was recorded when the flow rate stabilized.

3. Results and Discussion

3.1. Recovery Effect of Different Steam

Six rounds of steam-cycle stimulation experiments were carried out with steam at different temperatures (290.8 °C, 320.8 °C, and 350.8 °C). The comparison of the recovery conditions is shown in Figure 2, which shows that the final oil recovery efficiency gradually increases with the increase of temperature. The experimental results show that when the steam is superheated (350.8 °C), the oil recovery efficiency is the highest, and the recovery efficiency is 35.38%. When the steam is supersaturated steam (290.8 °C), the oil recovery efficiency is the lowest, and the recovery efficiency is 23.11%. Superheated steam can improve the recovery significantly, and the cumulative recovery efficiency is about 12% and 7% higher than that of supersaturated steam and saturated steam, respectively.
The analysis suggests that superheated steam has a higher enthalpy compared to the remaining two types of steam and a larger volume for the same amount of energy injected, which allows for a greater spread of the temperature field to move a deeper and wider range of oil. At the same time, higher temperatures can better reduce the viscosity of heavy oil and improve the rheological characteristics and micro-interfacial properties, making crude oil easier to extract. In addition, due to the thermal instability of macromolecular organic matter such as gum and asphaltene in heavy oil, steam can fully react with oil during the throughput process [40]. Therefore, distillation and pyrolysis of oil occur under the action of high-temperature steam, which makes the heavy components of crude oil decompose into light components, which are then easily mobilized to improve the overall recovery effect. However, the supersaturated steam carries less heat energy, has poor temperature diffusion ability, and rapidly condenses into water, which makes its liquid property more obvious, and the ability to use heavy oil at the far end of the well in a short time is further limited.
The comparative results of recovery in different cycles are shown in Figure 3. The results show that the main oil recovery cycle of SCS in the target block is the first four rounds, and the cumulative recovery rate can reach more than 85% of the total recovery. With the increase of injection steam temperature, the recovery degree of each round is obviously improved, and the differences of different steam recovery efficiency and produced components are mainly concentrated in the first few oil production cycles. Supersaturated steam produces more oil than the other two types of steam in the first few cycles, and the production capacity will gradually decline to the same as the other two types of steam in the next few cycles because the superheated steam produces most of the oil near the well in the first few cycles, so the superheated steam-cycle stimulation (SSCS) can reduce the production cycle to a certain extent. The oil production peak of supersaturated steam is later than that of the other two higher-temperature steams due to its slightly poorer diffusion rate and heat transfer capacity, which is limited by its own energy and condition and requires longer development time and more fluid injection [41]. At the same time, because superheated steam has a higher viscosity and carries small droplets, it has less gas channeling than CO2 displacement [42,43].

3.2. Metamorphic Characteristics of Clay

The clay component content in the target block accounts for about 10% of the total component. The specific results of clay mineral analysis on the core before and after steam injection are shown in Figure 4a. The clay content of the target reservoir is 30~32% kaolinite, 21~24% illite, 15~17% chlorite, and 28~30% Aemon mixed layer (of which smite is about 46~48%). Illite is a non-expansive mineral; because of the effect of interlayer K+, its hydration is weak. Kaolinite has low cation exchange capacity and poor hydration. Chlorite is an iron-rich mineral with acid sensitivity, but the injected steam is a high-pH fluid without acid sensitivity. Montmorillonite has a high cation exchange capacity and strong hydration, which increases the water sensitivity of the reservoir to some extent.
After SCS, the proportion of kaolinite decreased significantly, the content of the illite-montmorillonite mixed layer increased slightly, and the content of smectite increased significantly. At the same time, the results in Figure 5 show that with the increase of injected steam temperature, the conversion amount and conversion rate of each mineral are significantly increased. Compared with saturated steam, the conversion improvement effect caused by superheated steam is more obvious. First of all, the formation water in the target block has a high salinity, more than 22,000 mg/L, and presents CaCl2 water type. Therefore, there are more high-priced cations such as Ca2+ and Mg2+, and the temperature rises, strengthening the degree of ionization in the solution system, making the original alkaline water quality move more to the alkaline direction, strengthening the corrosion effect on the core and the original reaction. At the same time, high temperature will strengthen the dissolution effect of clay minerals in the fluid and enhance the solubility of mineral components. Differences in solubility with temperature not only result in differential changes in mineral content, but the increased content of different ions in water as a solute for chemical reactions upsets the chemical equilibrium that already exists in the solution; the chemical reactions then reoccur, producing new minerals.
More importantly, the temperature, as an important reaction condition, seriously affects the direction and effect of the metamorphism between clay minerals, which is the fundamental reason for the higher amount and rate of change of kaolinite and montmorillonite relative to the rest of the minerals, as well as the change of illite from a negative growth rate to a positive growth rate, as seen in the figure. Ilmenite and montmorillonite have an interconversion relationship. At temperatures lower than 250 °C, with relatively sufficient Na+, Ca2+, and Mg2+ in the formation, ilmenite will be converted to montmorillonite through the K+ removal reaction [44], which is shown in Equation (3). However, with the increase of temperature and pH, montmorillonite will transform into illite. When the temperature is higher than 250 °C and the alkaline environment is rich in Na+ or K+ ions, montmorillonite will generate illite by adding K+ reaction, which is shown in Equation (4). The experimental results show that the amount and rate of change of the components of kaolinite is relatively high, which is due to the fact that kaolinite is unstable under alkaline conditions and generally begins to dissolve at pH = 9 and T = 150 °C. The reaction formula for its generation of montmorillonite is shown in Equation (5). Kaolinite will also be converted into chlorite to some extent under high temperature and pressure, and its reaction formula for generating chlorite is shown in Equation (6).
On the whole, the change of mineral composition is mainly concentrated in kaolinite and montmorillonite, and the influence of thermal fluid on the metamorphism of clay minerals is not obvious at the laboratory scale in a short time. Firstly, because of the short reaction time, the evolution of rock minerals is a long process, often occurring in a stratigraphic environment for thousands of years before gradually forming a stable stratigraphic landscape. On the other hand, the temperature of the thermal fluid decreases rapidly during the flow process, and it is difficult to maintain the high temperature continuously, so the effect of mineral metamorphism is not very obvious.
K0.75(Al1.75R)(Si3.5Al0.5O10)(OH)2 + Na+(Mg/Ca) + SiO2 → (Na,Ca)0.33(Al,Mg)2(Si4O10)(OH)2·nH2O + K+
(Na,Ca)0.33(Al,Mg)2(Si4O10)(OH)2·nH2O + K+ → I/S → K0.75(Al1.75R)(Si3.5Al0.5O10)(OH)2
Na+(Ca2+) + Al4(Si4O10)(OH)8 + H4SiO4 → (Na,Ca)0.33(Al,Mg)2(Si4O10)(OH)2·nH2O + H2O + H+
5CaMg(CO3)2 + Al2Si2O5(OH)4 + SiO2 + H2O → 5CaCO3 + 5CO2 + Mg5Al2Si3O10(OH)8

3.3. Flow Velocity Sensitivity

The target block in the Lvda Oilfield is a high-porosity, high-permeability sandstone reservoir with good physical properties. The initial permeability of core#1 and core#2 was slightly lower, and the permeability first decreased, then increased, and finally stabilized. This is because the core of the target block is typical loose sandstone with weak compaction and a high content of kaolinite (accounting for more than 30% of the clay content). Therefore, in the early stage of water injection, the free particles inherent in the pores and the particles weakly consolidated with the pore wall easily fall off and migrate under the action of fluid erosion, so that the point support between the mineral debris particles is gradually inlaid more closely and the corresponding throat radius and pore connectivity are reduced, forming a “bridge block” and resulting in lower permeability. In the later stage, with the increase of flow rate, the permeability gradually increased (Figure 5), while the expelled liquid showed obvious turbidity, which indicated that a large number of particles were carried out by the fluid from the outlet of the rock samples, which in turn led to a rapid decrease in permeability.
In contrast, the initial permeability of core#3 and core#4 was higher, and the permeability does not have the decreasing stage but directly increases rapidly and then stays stable. This suggests that the deposition and plugging of particles have a greater correlation with the permeability of the loose sandstone. Core compaction is weak, the content of kaolinite is high, so the pore space is coarser, and the fluid flushing effect of particle transport makes the formation of a “bridge block” difficult. So as the flow rate increases, particles are constantly being carried out of the rock sample outlet by the fluid, resulting in a gradual increase in permeability. And when the flow velocity reaches a certain value, the change of permeability decreases significantly, which indicates that the easily migrated particles in the pore space of the formation will be taken out by the fluid almost completely after reaching a certain speed, and the remaining cemented and tightly packed rock constituents will be slowly influenced by the fluid with increasing flow rate, so that the permeability changes slowly. Meanwhile, the biggest difference between core#3 and core#4 is the length of the cores. The final permeability inflection point of the core#4 experiment with shorter cores is about 1 cm3/min in advance, which indicates that in the experiments, the shorter the core, the easier it is for the formation particles to flow out from the pore channels, the faster the permeability increase rate, the smaller the critical flow rate Qc, and the higher the permeability change rate.
According to the general definition, the increase of core permeability is a non-velocity-sensitive phenomenon. Through research, it is found that because the experimental core is relatively short, with high permeability and a large pore throat radius, fine particles will rush out of the core with the erosion of injected fluid, resulting in an increase in permeability, which also indicates that the reservoir has strong velocity sensitivity. In oilfield production, the reservoir thickness is much larger than the laboratory scale. Due to the long migration path of particles, they often cannot be flushed out of the reservoir but become blocked in a certain position of the reservoir. This will seriously damage the reservoir, resulting in increased water injection pressure and decreased water injection volume, eventually leading to the blockage of a certain injection well and sand production near the production well shaft. This already happened in core#3 and core#4 with low initial permeability.

3.4. Damage from Heavy-Component Deposition

The permeability measurement results of cores with different plugging degrees by using formation water and displacement water containing formation particles are shown in Figure 6. The experimental results show that when using ordinary formation water and formation water containing formation particles to displace the original core, the measured core permeability is similar, and the rate of change is only 1.08%. This indicates that for the reservoir with high porosity and high permeability, the same flow rate and the same reservoir matrix, fewer formation particles carried by the displacement fluid do not cause more damage to the original formation. It is easy to understand that the particles that can be brought out by the displaced fluid belong to the easily migrated particles that are not consolidated firmly and have the characteristics of small particle size, so when these migrated particles pass through the similar pore throat again, they will not be easily deposited and blocked again. However, when these particles pass through the finer throat of the pore, deposition may occur, resulting in decreased permeability.
The results in Figure 7 and Figure 8 show that when the migration particles and deposited heavy components were coupled, the impact caused on permeability was significantly higher, which indicates that heavy components were deposited and blocked in the core during thermal recovery of heavy oil. There were more asphaltenes and gums in the oil samples of the target blocks, especially the gum content of more than 20%, which is absorbed and deposited in the pore throat of the core, causing blockage and reducing the passing capacity of the core, resulting in a permeability drop of more than 30%. This also prevents the passage of particles that could have passed through the blank core without difficulty, allowing particles to be deposited in the throat of the core as well, which again exacerbates the blockage. This caused the permeability of the core to decrease further. At the same time, the influence of transported particles increases with the increase of blockage by deposition of heavy components in the core.
More importantly, it is found that the injected steam temperature seriously affects deposition blockage in the core. The results show that the permeability of the superheated steam group is significantly higher than that of the supersaturated steam group and the saturated steam group. At the same time, although the temperature gradient is the same for all three fluids, the permeability improvement is significantly higher for the superheated steam group than for the saturated steam group. On the one hand, the asphaltene and gum have higher solubility at high temperatures, and the dynamic equilibrium system of gum–asphaltene–oil is more stable, with lower viscosity and better fluidity, which is less likely to be retained and deposited at the pore throat [45]. On the other hand, although the temperature gradient of the three kinds of steam is the same, the superheated steam has a qualitative change in state, and its enthalpy and energy are significantly higher than that of the saturated steam. Further, the state of the superheated steam is a pure gaseous state, whereas the saturated steam, due to the difference in the degree of dryness, carries tiny droplets of gas, which will be turned into a liquid state more quickly in the process of expulsion, and so the expulsion is significantly weaker than that of the pure gaseous state.

4. Conclusions

This paper experimentally studied the effect of steam on the high-temperature transformation characteristics of clay minerals and the coupled damage of particle migration and heavy-component deposition. The main conclusions are described below.
  • The recovery of superheated steam is 12% and 7% higher than that of supersaturated steam and saturated steam. Superheated steam can reduce the production cycle to four rounds, which can reach more than 85% of the total recovery, improving the economics of the process.
  • Temperature increases the degree of clay metamorphism. During steam-cycle stimulation, kaolinite is converted to illite and chlorite by the K+ addition reaction, which increases the expansion damage to the reservoir.
  • In the laboratory, the blockage of particle migration at low flow rates can reduce the permeability by about 10%. Due to the loose core, high flow rates will flush particles out of the high permeability zone, making it difficult to form a blockage and increasing permeability by up to 50% or more. Due to the heterogeneity of the actual reservoir, these particles may be blocked in the small pore throat.
  • In the laboratory, particle migration has little effect on reservoir damage. Heavy-component deposition will reduce the core’s permeability, so the combination of formation particle migration and heavy-component deposition can lead to more than 30% reservoir damage.

Author Contributions

Conceptualization, Z.Z. and Y.Z.; methodology, Z.Z., H.Y. and D.L.; validation, L.Z., S.Y. and H.C.; formal analysis, W.H.; investigation, Z.Z., L.S. and N.W.; resources, Z.Z., L.S. and N.W.; data curation, L.Z.; writing—original draft preparation, Z.Z. and Y.Z.; writing—review and editing, Y.Z., H.C. and S.Y.; supervision, H.Y. and D.L.; project administration, W.H. and L.S.; funding acquisition, Z.Z., N.W., and L.Z. All authors have read and agreed to the published version of the manuscript.

Funding

This research received no external funding.

Data Availability Statement

The original contributions presented in the study are included in the article. Further inquiries can be directed to the corresponding author.

Conflicts of Interest

Authors Zuhao Zheng, Lu Zhang, Hongchao Yin, Dong Liu, Wei He, Leilei Shui and Ning Wang were employed by the company China National Offshore Oil Corporation. The remaining authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest. China National Offshore Oil Corporation had no role in the design of the study; in the collection, analyses, or interpretation of data; in the writing of the manuscript, or in the decision to publish the results.

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Processes 12 01959 g001
Figure 1. The experimental process of long-core steam-cycle stimulation.
Figure 1. The experimental process of long-core steam-cycle stimulation.
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Figure 2. Comparison of cumulative recovery situation.
Figure 2. Comparison of cumulative recovery situation.
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Figure 3. Comparison of recovery conditions in different rounds.
Figure 3. Comparison of recovery conditions in different rounds.
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Figure 4. Determination results of clay components: (a) changes in clay components after different steam-cycle stimulation experiments; (b) the change rate of clay components after different steam-cycle stimulation experiments.
Figure 4. Determination results of clay components: (a) changes in clay components after different steam-cycle stimulation experiments; (b) the change rate of clay components after different steam-cycle stimulation experiments.
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Figure 5. Speed sensitivity experiment results.
Figure 5. Speed sensitivity experiment results.
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Figure 6. The impact of sedimentation and migration coupling on permeability.
Figure 6. The impact of sedimentation and migration coupling on permeability.
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Figure 7. The decrease in permeability caused by particles.
Figure 7. The decrease in permeability caused by particles.
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Figure 8. The decrease in permeability caused by particles and heavy components, respectively.
Figure 8. The decrease in permeability caused by particles and heavy components, respectively.
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Table 1. Core parameters and usage.
Table 1. Core parameters and usage.
Length
(cm)		Diameter
(cm)		Porosity
(%)		Permeability
(mD)		Use
39.3422.50631.43986.4Cyclic steam stimulation-290.8 °C
39.2482.50431.83967.8Cyclic steam stimulation-320.8 °C
38.9622.49932.23959.1Cyclic steam stimulation-350.8 °C
5.3512.50734.3778.9Speed sensitivity experiment-Core #1
5.5882.50734.9953.1Speed sensitivity experiment-Core #2
5.1392.47536.21914.1Speed sensitivity experiment-Core #3
4.7732.50335.91904.4Speed sensitivity experiment-Core #4
Table 2. Experimental parameters of steam-cycle stimulation experiment.
Table 2. Experimental parameters of steam-cycle stimulation experiment.
SteamTemperature
(°C)		Injection Rate
(g/min)		Injection Time
(min)		Injection Weight
(g)		Closed Time
(min)
Supersaturated steam290.80.59855.9733.4613.5
Saturated steam320.80.60556.3134.0913.5
Superheated steam350.80.60456.2333.9413.5
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MDPI and ACS Style

Zheng, Z.; Zhang, L.; Yin, H.; Liu, D.; He, W.; Shui, L.; Wang, N.; Chen, H.; Yang, S.; Zhang, Y. Evaluation of Reservoir Damage by Hydrothermal Fluid from Clay Metamorphism, Particle Migration, and Heavy-Component Deposition in Offshore Heavy Oilfields. Processes 2024, 12, 1959. https://doi.org/10.3390/pr12091959

AMA Style

Zheng Z, Zhang L, Yin H, Liu D, He W, Shui L, Wang N, Chen H, Yang S, Zhang Y. Evaluation of Reservoir Damage by Hydrothermal Fluid from Clay Metamorphism, Particle Migration, and Heavy-Component Deposition in Offshore Heavy Oilfields. Processes. 2024; 12(9):1959. https://doi.org/10.3390/pr12091959

Chicago/Turabian Style

Zheng, Zuhao, Lu Zhang, Hongchao Yin, Dong Liu, Wei He, Leilei Shui, Ning Wang, Hao Chen, Shenglai Yang, and Yiqi Zhang. 2024. "Evaluation of Reservoir Damage by Hydrothermal Fluid from Clay Metamorphism, Particle Migration, and Heavy-Component Deposition in Offshore Heavy Oilfields" Processes 12, no. 9: 1959. https://doi.org/10.3390/pr12091959

APA Style

Zheng, Z., Zhang, L., Yin, H., Liu, D., He, W., Shui, L., Wang, N., Chen, H., Yang, S., & Zhang, Y. (2024). Evaluation of Reservoir Damage by Hydrothermal Fluid from Clay Metamorphism, Particle Migration, and Heavy-Component Deposition in Offshore Heavy Oilfields. Processes, 12(9), 1959. https://doi.org/10.3390/pr12091959

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