Experimental Investigation into the Mechanisms of Liquid-Phase Damage in Shale Oil Reservoirs: A Case Study from the Leijia Area

Abstract

The fourth member of the Shahejie Formation in the Leijia area of the western depression of the Liaohe Oilfield represents a typical shale oil reservoir. However, post-hydraulic fracturing operations in this region are often hindered by significant discrepancies in well productivity, low fracturing fluid flowback efficiency, and an unclear understanding of reservoir damage mechanisms during fracturing. These challenges have become major bottlenecks restricting the efficient exploration and development of shale oil in this block. In this study, a series of laboratory-simulated experiments were conducted to investigate the primary mechanisms of formation damage induced by fracturing fluids in shale oil reservoirs. An experimental methodology for evaluating reservoir damage caused by fracturing fluids was developed accordingly. Results indicate that guar gum-based fracturing fluids exhibit good compatibility with formation-sensitive minerals, resulting in relatively minor damage. In contrast, capillary trapping of the aqueous phase leads to moderate damage, while polymer adsorption and retention cause low to moderate impairment. The damage associated with fracturing fluid invasion into fractures is found to be moderately high. Overall, the dominant damage mechanisms of guar gum fracturing fluids in the Shahejie Member 4 shale oil reservoir are identified as aqueous phase trapping and polymer adsorption. Based on the identified damage mechanisms, corresponding optimization strategies for fracturing fluid formulations are proposed. The findings of this research provide critical insights for improving shale oil development strategies in the Leijia area.

1. Introduction

Exploration and development practices in China’s continental basins have revealed that shale strata with diverse types and widespread distribution are extensively developed in lacustrine basin centers. Shale oil has thus emerged as a significant frontier in domestic petroleum exploration and development, representing a key replacement resource for the future [1,2,3]. Due to the extremely low matrix permeability of shale oil reservoirs, natural productivity is generally absent, and hydraulic fracturing has become an essential technique for the effective extraction of shale oil resources [4,5]. However, the unique characteristics of shale reservoirs—including narrow pore throats, high contents of formation-sensitive minerals, and strong interfacial tension—make them particularly susceptible to formation damage during hydraulic fracturing. Such damage can significantly reduce post-fracturing well productivity and constitutes a major bottleneck to the efficient development of shale oil [6,7,8,9,10,11,12,13].

The Lejia region is situated in the middle segment of the western depression within the Liaohe Depression, on the Shubei–Gaosheng slope. During the Sha 4 stage of the Paleogene period, the sedimentary environment in this area was of the coastal and shallow-lake facies. Moving further eastward, the water depth increased, leading to the development of a semi-deep lake to deep-lake facies. The primary rock types of the reservoir are dolomites. These rocks exhibit poor physical properties and a high mud content, thus classifying them as typical mixed-sedimentary shale oil reservoirs [14,15]. The porosity of the reservoir core varies from 1.68% to 11.65%, with the majority concentrated between 4% and 8%, accounting for 67.31%. The permeability mainly ranges from 0.01 mD to 6.35 mD. Currently, shale oil wells in the Member 4 of the Shahejie Formation in the Leijia area exhibit several production challenges, including low post-fracturing fluid flowback efficiency, significant variability in well productivity, and poorly understood mechanisms of reservoir damage. These issues have resulted in insufficiently targeted designs of working fluid systems.

In this study, the Member 4 shale oil reservoir in the Leijia area was selected as the research object. Laboratory simulation experiments were conducted to evaluate the degree of formation damage induced by guar gum-based fracturing fluids. Additionally, a combination of analytical techniques—including scanning electron microscopy (SEM) and nuclear magnetic resonance (NMR)—was employed to systematically investigate the dominant damage mechanisms caused by the fracturing fluid. Based on the findings, optimization strategies for fracturing fluid systems were proposed, providing technical support for the design of efficient shale oil development programs in the Leijia area.

2. Samples and Methods

2.1. Experimental Samples

All the samples used in the experiment were taken from the same wellbore; the XRD results of the experimental samples are as shown in

Table 1. XRD results of experimental samples.

Dolomite	Quartz	Feldspar	Mordenite	Clay Minerals	Clay Mineral Content (%)
(%)	(%)	(%)	(%)	(%)	I	I/S
32.81	19.3	11.2	6.4	18.5	24.1	71.2

Note: I: Illite; I/S: Illite/Smectite mixed layer. The mixed layer ratio is 5–10%.

. The dolomite content averages 32.81%, the clay minerals average 18.5%, quartz averages 19.3%, feldspar averages 11.2%, and mordenite averages 6.4%. Illite and illite/smectite mixed layers dominate the clay mineral assemblage. The average relative percentage of illite is 24.1%, the average relative content of illite–smectite mixed layers is 71.2%, and the mixed layer ratio is 5–10%. Figure 1a,b shows two types of dolomite morphology.

The reservoir exhibits an average porosity of 6.01% and an average permeability of 1.12 mD, indicating the characteristics of a low-permeability, tight reservoir. The storage space mainly comprises secondary dissolution pores, organic matter-hosted pores, intercrystalline pores, and dissolution fractures (Figure 1c,d). The maximum pore throat radius ranges from 0.54 to 1.67 μm, with an average pore throat radius between 0.078 and 0.186 μm. These parameters reflect the development of fine-scale pore throats with poor connectivity, which significantly constrain fluid flow within the reservoir.

2.2. Fracturing Fluid System

In the Leijia area of the western depression in the Liaohe Oilfield, the Member 4 shale oil reservoir of the Shahejie Formation employs a guar gum-based fracturing fluid system. The formulation consists of 0.36% guar gum, 0.05% buffer, 0.05% clay stabilizer, 0.1% flowback aid, and 0.05% pH regulator. The prepared base fluid of the fracturing system is shown in Figure 2.

Based on the petroleum industry standard SY/T 5107-2016 [16] “Performance Evaluation Methods for Water-Based Fracturing Fluids,” a series of basic performance tests were conducted on the guar gum fracturing fluid system. The experimental results are presented in

Table 2. Performance evaluation results of the guar gum fracturing fluid in the Leijia area.

Breaker Time (min)	Apparent Viscosity of Base Fluid (mPa·s)	Viscosity of Crosslinked Fluid (mPa·s)	Viscosity After Gel Break (mPa·s)	Interfacial Tension (mN/m)	Residue Content (mg/L)
120	56.2	73.9	4.3	6.09	206.3

. As shown, the guar-based fracturing fluid exhibits relatively high interfacial tension and residue content compared with commonly accepted technical benchmarks.

2.3. Equipments

The information of the instruments and equipment used in this experiment is as follows: ① CMS-300 core analysis instrument, Core Company, Houston, TX, USA; ② ZYB-III type vacuum pressure saturation device, Jiangsu Lianyou Petroleum Instrument Co., Ltd., Hai’an County, Jiangsu, China; ③ CWCT-II type high-temperature and high-pressure reservoir damage evaluation device, Chengdu Haohan Rock Electric Technology Co., Ltd., Chengdu, China; ④ FEI Quanta 650 FEG field emission scanning electron microscope, Brno, FEI Czech Republic; ⑤ MacroMR12-150-HTHP-I high-temperature and high-pressure nuclear magnetic flow visualization analysis and imaging system, Suzhou Newmai Analytical Instrument Co., Ltd., Suzhou, China.

2.4. Potential Damage Mechanisms

The potential damage mechanisms of guar gum fracturing fluid to shale are mainly classified into four categories, as shown in Figure 3.

(1)

Compatibility-Induced Damage Between Fracturing Fluid and Reservoir Minerals

When fracturing fluids enter the reservoir, a variety of physicochemical reactions may occur with sensitive minerals, leading to mineral swelling, dispersion, and migration. These processes reduce the effective pore space for fluid flow, block seepage channels, and ultimately result in a decline in core permeability, thereby causing damage to the reservoir [17,18]. In the Member 4 reservoir, clay minerals are predominantly illite and illite–smectite mixed layers, which are highly susceptible to water sensitivity and salinity sensitivity, increasing the risk of formation damage.

(2)

Water Phase Trapping Damage

The Member 4 reservoir of the Shahejie Formation is characterized by extremely fine pore-throat structures and poor connectivity, making it difficult for the invading aqueous phase to flow back after hydraulic fracturing. This readily leads to water phase trapping damage. The severity of such damage is largely controlled by the content of illite in the clay minerals [19,20]. In this reservoir, illite is the dominant clay component. Its platy morphology tends to partition pore throats and pore spaces, thereby exacerbating the potential for aqueous phase entrapment within the reservoir.

(3)

Reservoir Damage Caused by Fracturing Fluid Thickeners

Fracturing fluid thickeners can cause reservoir damage primarily through two mechanisms [21,22,23]:

① Residues generated after gel breaking may block pore throats;

② High-molecular-weight polymers in the fracturing fluid can adsorb onto pore walls, leading to pore throat narrowing or blockage, thereby reducing the matrix permeability of the reservoir.

At present, guar gum-based fracturing fluids are predominantly used in the Leijia area shale oil wells. The potential damage associated with thickeners in such systems should not be underestimated.

(4)

Incompatibility Between Fracturing Fluids and Formation Fluids

The compatibility evaluation experiment between fracturing fluids and formation fluids primarily investigates the chemical reactions that occur when the fracturing fluid enters the reservoir and interacts with in situ fluids. These reactions may lead to scaling and precipitation, which reduce the effective pore space, block seepage channels, and ultimately result in a decline in core permeability, thereby causing damage to the reservoir [22,23].

2.5. Experimental Methods

At present, studies on the evaluation methods of fracturing fluid-induced damage in shale oil reservoirs remain limited. The degree of formation damage is primarily assessed by monitoring changes in core permeability [24,25,26]. Existing evaluation methodologies largely rely on industry standards developed for conventional reservoirs, including SY/T 5358-2010 [27], SY/T 6540-2021 [28] and SY/T 5107-2016 [16].

However, these standardized methods mainly target conventional oil and gas reservoirs and are partially inapplicable to shale oil systems. As a result, the dominant damage mechanisms induced by fracturing fluids in shale reservoirs cannot be effectively identified through conventional testing protocols, limiting their utility in guiding the formulation and optimization of shale-specific fracturing fluid systems.

In this study, based on the analysis of potential damage mechanisms in the Member 4 reservoir of the Shahejie Formation, targeted experimental evaluations were conducted focusing on single damage factors such as fluid–mineral incompatibility, water phase trapping, and polymer-induced damage. These tests were complemented by advanced characterization techniques, including scanning electron microscopy (SEM) and nuclear magnetic resonance (NMR), to systematically investigate the primary mechanisms by which fracturing fluids damage the reservoir. The findings provide a scientific basis for optimizing fracturing fluid systems for shale oil development in the Leijia area.

The experimental procedures were refined in reference to relevant petroleum industry standards, with specific adjustments summarized in

Table 3. Limitations of existing experimental methods for shale oil reservoir damage evaluation and proposed improvements.

No.	Identified Issues	Proposed Improvements and Optimization Measures
1	Dense matrix leading to poor displacement efficiency	Apply backpressure to enhance permeability of tight cores; use pulse decay method for permeability measurement
2	Difficulty in saturating core samples with formation fluids	Employ vacuum extraction with molecular pumps and pressure-assisted saturation techniques
3	Absence of initial water saturation conditions	Establish initial water saturation using capillary imbibition; apply vacuum and pressurized saturation methods for oil saturation
4	Limited evaluation parameters and insufficient understanding of damage mechanisms	Utilize environmental scanning electron microscopy (ESEM) and nuclear magnetic resonance (NMR) to characterize mineral and pore structure alterations before and after fluid exposure, thus enhancing understanding of damage mechanisms

.

3. Results and Discussions

3.1. Compatibility Between Fracturing Fluid and Reservoir Minerals

The experimental procedure is as follows:

(1)

The experimental core was washed of oil and salt, dried to a constant weight, and then the basic parameters such as the core length and diameter were measured. The porosity and permeability of the core were tested.

(2)

The experimental core was evacuated and saturated with formation water under pressure. The T2 spectrum distribution of the core before the experiment was tested using a nuclear magnetic resonance instrument.

(3)

The base fluid of the fracturing fluid was prepared according to the fracturing fluid system formula (without adding thickener), and was left to stand for 24 h and then finely filtered for later use.

(4)

The initial permeability K1 of the experimental core was measured in the forward direction using formation water under a certain flow rate.

(5)

The finely filtered base fluid of the fracturing fluid was used to displace 10–12 PV in the reverse direction. The reaction was carried out at the reservoir temperature (90 °C) for 24 h.

(6)

The formation water was used to backflow in the forward direction under a constant flow rate to test the permeability K₂ of the core after backflowing formation water, and the permeability damage rate Ir of the core was calculated.

(7)

The T2 spectrum distribution of the core after dynamic damage was tested using a nuclear magnetic resonance instrument. The microscopic structural characteristics such as the pore structure and mineral occurrence of the core after the experiment were observed using a field emission scanning electron microscope.

3.1.1. Experimental Results

To accurately and quantitatively evaluate the compatibility between the fracturing fluid and the mineral components of low-permeability tight reservoirs, while eliminating the influence of other potential damage mechanisms, a single-phase experimental fluid was employed in this study. The experimental fluid was prepared using the base water from the fracturing fluid formulation, which shares similar physicochemical properties with the post-gel-breaking fluid. This design ensures a more representative assessment of the interaction between the fracturing fluid and reservoir minerals.

Since only single-phase flow was present in the core samples, capillary end effects such as water phase trapping were effectively excluded. Moreover, no polymer thickener was added to the experimental fluid, thereby eliminating potential formation damage associated with polymer retention or residue. This controlled approach isolates mineral-related sensitivity responses and enables a more precise evaluation of fluid–mineral compatibility.

The experimental evaluation results are summarized in

Table 4. Experimental Results of Compatibility Evaluation Between Guar Gum Fracturing Fluid and Reservoir Minerals.

No.	Well ID	Well Depth (m)	Formation Interval	KW1 (mD)	KW2 (mD)	Ir (%)
1	Lei 88-59-85	3508.50	Shahejie Formation Member 4	17.377	15.625	89.92
2	Lei 88-59-85	3496.57	Shahejie Formation Member 4	1.927	1.586	82.30
3	Lei 88-59-85	3495.57	Shahejie Formation Member 4	1.531	1.380	90.11
4	Lei 88-59-85	3484.18	Shahejie Formation Member 4	0.932	0.792	84.98

Note: K_w1: Initial permeability measured with formation water; K_w2: permeability after backflow of formation water following reaction with fracturing fluid base; Ir: permeability recovery of core samples.

. After interaction between the guar gum fracturing fluid system and the sensitive minerals in the Member 4 reservoir of the Shahejie Formation, the average permeability recovery of the core samples reached 86.82%, indicating a low level of formation damage.

3.1.2. Evaluation and Analysis

The compatibility between the fracturing fluid and reservoir minerals is primarily influenced by the absolute content of illite and illite/smectite mixed-layer clays, as well as the overall clay mineral content in the core samples [29,30,31]. Environmental scanning electron microscopy (ESEM) was conducted to analyze the microstructure of core samples before and after the compatibility evaluation. As shown in Figure 4, the mineral surfaces within the cores remained clean, with no evidence of clay swelling, particle dispersion, or pore blockage.

Quantitative analysis of the pore structure before and after the compatibility tests was also performed, and the results are presented in Figure 5. The pore throat radii of the cores were mainly distributed in the range of 0.01–0.5 μm, with minimal variation observed between the pre- and post-test samples.

Overall, the guar-based fracturing fluid system demonstrated good compatibility with the sensitive minerals in Member 4 of the Shahejie Formation in the Leijia area, resulting in only minor damage. This can be attributed to the presence of clay stabilizers and anti-swelling agents in the fluid formulation, which effectively inhibited the swelling and dispersion of sensitive clay minerals, despite the presence of illite/smectite mixed-layer minerals in the reservoir.

3.2. Water Phase Trapping

The experimental procedure is as follows:

(1)

The experimental core was washed of oil and salt, dried to a constant weight, and then the basic parameters such as the core length and diameter were measured. The porosity and permeability of the core were also tested.

(2)

The experimental core was initially saturated with water by capillary self-attraction, then vacuumed and pressurized to saturate with kerosene.

(3)

Under a certain flow rate, the initial permeability K₁ was measured by forward kerosene flow. The initial water saturation S_w1 of the core was also tested by nuclear magnetic resonance.

(4)

The experimental core was displaced with 1–2 PV of the base fluid of the fracturing fluid in the reverse direction and was left to fully saturate for 1 h at the reservoir temperature (90 °C).

(5)

Under a constant speed, the core was forwardly backflushed with kerosene to test the oil phase permeability K₂. The water saturation S_w2 of the core after water lock damage was tested by nuclear magnetic resonance. The permeability damage rate Ik of the core was calculated.

3.2.1. Experimental Results

To eliminate the influence of compatibility-related damage between the fracturing fluid and sensitive minerals during the water phase trapping experiment, the contact time between the fracturing fluid and the reservoir core was limited to 1 h. Additionally, the experimental fluid was prepared using the base fluid of the fracturing system without any added polymers, thereby avoiding permeability impairment caused by polymer adsorption and retention. These measures ensured that the test results accurately reflected the extent of water phase trapping damage induced by the fracturing fluid.

The experimental results of water phase trapping are summarized in

Table 5. Experimental results of water phase trapping damage induced by fracturing fluid.

No.	Well ID	Well Depth (m)	Formation Interval	K1 (mD)	Sw1 (%)	K2 (mD)	Sw2 (%)	Ik (%)
1	Lei 88	3487.18	Shahejie Formation Member 4	1.985	52.16	1.037	62.32	52.24
2	Lei 88	3498.70	Shahejie Formation Member 4	3.211	49.88	1.930	53.42	60.11
3	Lei 88	3498.57	Shahejie Formation Member 4	3.014	40.29	1.782	50.25	59.12
4	Lei 96	3080.02	Shahejie Formation Member 4	0.676	42.76	0.320	52.65	47.34

Note: K₁: Oil phase permeability of core under initial water saturation conditions; S_w1: initial water saturation of core; K₂: oil permeability after invasion–backflow; S_w2: water saturation after invasion–backflow; Ik: permeability recovery of experimental core.

. After fluid invasion and subsequent backflow, the average permeability recovery of the core samples was 54.70%, indicating a moderate level of water phase trapping damage.

3.2.2. Evaluation and Analysis

The extent of water-lock damage is influenced by multiple factors, including the size and distribution of reservoir pore throats, mineral composition, interaction pressure and duration between foreign fluids and the rock matrix, initial water saturation, and wettability [26,29]. The controlling factors affecting water phase trapping damage in the Shahejie Formation of the fourth member (Sha 4) can be summarized into the following four categories:

① Reservoir Pore Structure: The pore throat diameters of the Sha 4 shale oil reservoir are small. As crude oil flows through these narrow channels, it encounters increased resistance, leading to flow interruption. This causes the oil to disperse into numerous oil droplets, thereby increasing flow resistance.

② Type and Content of Clay Minerals: The content of illite in the clay minerals significantly influences the degree of water phase trapping damage. In the Sha 4 reservoir, clay minerals are predominantly illite. When polar molecules in the fracturing fluid interact with illite, they adhere to the surface of mineral particles, exacerbating the water phase trapping damage [32,33].

③ Movable Fluid Saturation: Shale oil reservoirs generally exhibit a sub-bound water state, with initial water saturation lower than bound water saturation [34]. Consequently, the reservoir possesses strong bound water potential, making it difficult for invading water phase fluids to be effectively flowed back, resulting in water phase trapping damage. The average movable fluid saturation in the Sha 4 reservoir is approximately 33.97%, indicating that the fracturing fluid invading the reservoir is difficult to fully flow back.

④ Wettability: The Sha 4 reservoir exhibits strong hydrophilicity. Upon invasion by water-based fracturing fluids, the wetting phase is water, and combined with the relatively high interfacial tension of the guar gum fracturing fluid system, this leads to difficulty in fluid flowback after invasion.

3.3. Polymer Adsorption and Retention Damage

The experimental procedure is as follows:

(1)

The experimental core was washed of oil and salt, dried to a constant weight, and then the basic parameters such as core length and diameter were measured. The porosity and permeability of the core were tested.

(2)

The guar gum fracturing fluid system was prepared according to the formula and then broken down. The broken-down fracturing fluid was centrifuged using a high-speed centrifuge, and the clear broken-down fluid at the top was reserved for later use.

(3)

The experimental core was evacuated and pressurized to be saturated with formation water.

(4)

Under a certain flow rate, the initial permeability K₁ was measured in the forward direction using formation water. The T2 spectrum distribution of the core was tested using a nuclear magnetic resonance instrument.

(5)

The core was displaced in the reverse direction with 1–2 PV of the broken-down fracturing fluid, and then left to stand for 2 h at the reservoir temperature (90 °C).

(6)

The core was tested for natural flowback permeability K₂ in the forward direction using formation water. During the flowback process, the water phase was collected for ESEM environmental scanning electron microscopy observation, and the natural permeability recovery rate Ik was calculated.

(7)

The T2 spectrum distribution of the core after polymer damage was tested using nuclear magnetic resonance. The microscopic structural characteristics of the core after the experiment were observed using a scanning electron microscope.

3.3.1. Experimental Results

The permeability reduction of the reservoir caused by the plugging of pore spaces due to fracturing fluid residues and the adsorption-retention of polymer molecules within the pore throats collectively constitutes the thickening agent damage of fracturing fluids [35]. Given the poor physical properties and fine pore structure of the shale oil reservoir matrix, residue from broken gels is difficult to penetrate into the matrix. Therefore, this study primarily evaluates the damage severity caused by polymer adsorption and retention from the broken gel fluid in the fracturing fluid system.

To this end, the broken gel fluid was subjected to high-speed centrifugation, and the supernatant was collected as the test fluid. The reaction time between the fracturing fluid and the core was limited to one hour to avoid damage induced by sensitive minerals. Additionally, a single-phase fluid (formation water) was used during the experiment to exclude water-phase trapping damage.

The evaluation results of polymer adsorption and retention damage are summarized in

Table 6. Experimental results of polymer adsorption and retention damage evaluation of fracturing fluid.

No.	Well ID	Well Depth (m)	Formation Interval	K1 (mD)	K2 (mD)	Ik (%)
1	Lei 88-59-85	3497.67	Shahejie Formation Member 4	1.113	0.732	65.75
2	Lei 96	3124.60	Shahejie Formation	0.920	0.698	75.87
3	Lei 88-59-85	3500.37	Shahejie Formation	0.684	0.405	59.23
4	Lei 88-59-85	3508.50	Shahejie Formation	1.289	0.863	66.94

Note: K₁: Initial permeability of core samples saturated with formation water; K₂: permeability after backflow following polymer adsorption of fracturing fluid; Ik: permeability recovery of experimental core.

. After polymer adsorption within the reservoir pore throats, the core permeability recovery rate averaged 66.95%, indicating a damage level ranging from moderate to mild.

3.3.2. Evaluation and Analysis

Environmental scanning electron microscopy (ESEM) observations of the fracturing fluid polymers prior to experimentation revealed that the guar-based fracturing fluid polymers exhibited a dense network and chain-like morphology (Figure 6a). Previous studies have demonstrated that such polymer structures possess strong adsorption capacity upon entering the core, readily adhering to the surfaces of rock particles. During migration, this adsorption can lead to the detachment of particles from the pore walls [20,21]. After passing through the core and undergoing shear, the network structure of the guar polymer was disrupted, resulting in a reduced density (Figure 6b). The originally dense network and chain-like structures disappeared, leaving only fibrous molecular forms, indicating significant polymer adsorption by the core.

The pore throat distribution of the core before and after the thickening agent damage experiment was also analyzed, with results shown in Figure 7. After the core was subjected to fracturing fluid backflow, noticeable changes occurred in the pore throat size distribution: the proportion of smaller pore throats increased, while that of larger pore throats decreased. Consequently, the pore throats contributing most significantly to permeability shifted from larger to smaller sizes. This phenomenon is attributed to the fact that prior to polymer adsorption and residue damage, the permeability of the Sha-4 reservoir was predominantly contributed by larger pore throats. During the experiment, the fracturing fluid preferentially entered the larger pore throats, where the polymer structure was disrupted and adsorbed onto the pore walls. This adsorption effectively reduced the pore throat sizes that contribute most to the core permeability, increasing the proportion of smaller pore throats. Overall, polymer adsorption retention is identified as one of the primary mechanisms causing damage to the reservoir by the guanidine-based fracturing fluid.

4. Suggestions

Based on the above analysis, the primary damage mechanisms of guanidine gum fracturing fluid on the Sha-4 shale oil reservoir in the Leijia area include the following: (a) water-phase blockage damage; (b) adsorption and retention of polymer macromolecules causing pore throat blockage; (c) residue-induced blockage on fracture surfaces; and (d) polymer adsorption retention on natural fracture surfaces. Correspondingly, the following reservoir protection measures are proposed:

(1)

Enhance the gel-breaking performance of the fracturing fluid to ensure thorough hydration and gel breaking, thereby reducing the viscous resistance during fluid flow within the formation.

(2)

Incorporate highly effective flowback agents in the fluid system to reduce oil–water interfacial tension. Given that the reservoir pore throats are predominantly micro- and nano-scale and that bound water potential is significant, the selection of flowback agents must be optimized specifically for the reservoir characteristics of the study area.

(3)

Promote rapid gel breaking of the fracturing fluid and employ small-diameter nozzles post-fracturing to utilize residual pressure for forced fracture fluid flowback, minimizing fluid retention time in the reservoir.

(4)

Utilize auxiliary flowback methods such as liquid nitrogen or CO₂ injection to enhance fluid removal from the fractures.

(5)

Apply interfacial modification techniques to alter the wettability of the rock surface by adjusting surface energy or morphology, thereby mitigating the degree of water-phase blockage damage.

(6)

Adopt low-residue or residue-free, easily breakable, and low-polymer concentration water-based fracturing fluid systems, such as clean fracturing fluids or low-concentration polymer fluids, to further reduce formation damage.

5. Conclusions

(1)

Based on relevant petroleum and natural gas industry standards and the geological characteristics of shale oil reservoirs, an effective experimental evaluation method for assessing fracturing fluid damage to shale oil reservoirs was developed. This method enables the identification and quantification of different damage mechanisms caused by fracturing fluids, thereby providing valuable guidance for the design and optimization of fracturing fluid systems.

(2)

Experimental evaluation results indicate that the primary damage mechanisms of fracturing fluids to the shale oil reservoir in the Leijia area are water-phase blockage and polymer adsorption retention. It is recommended to adopt water-based fracturing fluid systems with low or zero residue, easy gel breaking, and low polymer concentration; to select highly efficient flowback agents; and to apply interfacial modification technologies to alter reservoir wettability. These measures effectively improve fracturing fluid performance and protect the shale oil reservoir.