Aiming at the characteristics of cluster horizontal well drilling operations, efficient and mobile drilling rig technology and batch drilling modes for cluster horizontal wells were developed through technological breakthroughs. Additionally, industrialized operation has reduced the moving time between wellheads to 30 min. For example, 60 horizontal wells were drilled by 20 cluster horizontal well groups to develop four formations in the Permian Basin, reducing operational costs by 6% to 8% ^[12]. Some super well pads can accommodate up to 64 wells to develop five formations.

To achieve economic development of shale oil and gas, oil and gas companies in the United States have developed a super one-trip drilling technology that integrates PDC (polycrystalline diamond compact) bit, long-life screw and rotary steerable system. The application of rotary steerable systems exceeds 90%, and it has become common to complete the buildup section and horizontal section of a horizontal well at one trip. In the Permian Basin, Eagle Ford, and Bakken shale oil, the one-trip footage reached 4 448, 5 790 and 4 000 m, respectively, significantly improving drilling efficiency and reducing drilling costs. For example, Baker Hughes only used 3.5 d to complete a 5 405 m deep horizontal shale oil well in the Denver-Julesburg Basin in the United States ^[13].

The introduction of automatic and intelligent systems has significantly improved drilling efficiency and safety ^[14], representing a trend in the drilling industry. Oil and gas companies in the United States have implemented an intelligent closed-loop drilling system composed of real- time geological parameter measurement, dual-direction information transmission between surface and downhole, and surface monitoring to realize automatic and efficient horizontal well drilling operation as well as remote control on directional drilling tools, and increased the rate of penetration (ROP) by 27.5% ^[15].

The iterative progress of drilling technology has laid a solid foundation for cost reduction and efficient development of shale oil in the United States ^[16-17]. The drilling cycle has been significantly shortened. As evidenced by Southwest Energy, the average horizontal section increased from 1 097.9 m to 1 872.1 m, and the drilling cycle reduced from 25.6 d to 9.0 d in the Appalachia block ^[18]. The “one-trip” drilling technology further reduced the drilling cycle to 5-10 d ^[19-20]. The ROP increased from 79.25 m/d in 2012 to 329.18 m/d in 2018, by 315.38% ^[21]. The length of the horizontal section also increased significantly, generally around 3 000 m ^[21-22] for shale oil wells. The well construction cost decreased from $6 800 per meter in 2012 to approximately $3 333 per meter in 2022 ^[23].

The combined application of horizontal well and fracturing technology has significantly enhanced the effectiveness of shale oil and gas development, and achieved leapfrog progress. Staged fracturing technology in horizontal wells can greatly increase the contact between reservoirs and fractures, which results in a multiplicative increase in stimulation effects compared with vertical well fracturing stimulation. The first-generation fracturing technology focuses on fracturing reservoirs and creating long fractures on both wings. However, it is accompanied by a small number of stages and clusters, larger cluster spacing, lower pumping rate, and lower proppant concentration. The first-generation horizontal well fracturing technology is still in its infancy, and the key fracturing technical indicators are low.

Limited by reservoir conditions, well patterns, and fracturing processes, only increasing fracture length doesn’t significantly enhance shale oil and gas production. To achieve efficient development of shale oil and gas, a complex fracture system is constructed with major fractures as the primary component and branch fractures as the secondary component, and this kind of fracture system means three-dimensional stimulation to shale reservoirs. Under favorable market and policy conditions, new operation models and techniques were developed, including well pad/group, synchronous fracturing, zipper fracturing, extreme limited-entry perforation, integrated variable-viscosity fracturing fluid system, fully soluble bridge plugs, and quartz sands (replacing ceramic proppants). These achievements doubled fracturing efficiency. In addition, fracturing parameters such as horizontal section length, cluster spacing, fracturing fluid volume and proppant concentration were updated, too. As a result, the single well production was enhanced while engineering costs declined.

Dense and short fractures are usually induced ^[28] to increase the stimulated reservoir volume (SRV) near wellbore. With the decrease in well spacing, fracturing process gradually evolved from “multiple stages + fewer clusters + proppant slugs” to “multiple cluster dense cutting + limited-entry fracturing + temporary plugging and diverting”. The combination of super well pads with the fracturing technology featured by large fracturing fluid volume, high proppant concentration and small cluster spacing has increased fracturing fluid volume and proppant concentration by approximately two times and reduced comprehensive sand-fluid ratio by over 10%. This significantly improved the fracturing stimulation effect and led to a great increase in shale oil and gas production ^[29-30]. Furthermore, quartz sands and slickwater contributed to continuous reduction in fracturing costs.

The technology of precise sweet spot evaluation is the foundation for achieving beneficial development of shale oil. The evaluation on sweet spots of shale oil in the Jiyang continental rift lake basin has primarily experienced two stages: the “four-property” favorable lithology evaluation during the early exploration stage and the geological-engineering “dual sweet spot” evaluation during the development pilot stage ^[41].

Rock physics experiments on cores and logging curves (DEN, CN and AC) were used to estimate the “four kinds of properties” of shale reservoirs (reservoir physical properties, oil-bearing property, fluid mobility, and fracturability) during the early exploration stage, and a multi-mineral volume model was established for Jiyang shale oil reservoirs. Based on multiple logging response equations, the volume fractions of various mineral components and fluids, as well as the content of brittle minerals were calculated. Fitting logging curves, multi-mineral inversion, and other methods were used to quantitatively evaluate reservoir porosity and permeability. Geochemical parameters like TOC (total organic carbon content) and R_o (reflectance of organic matter) were calculated through fitting logging curves, curve overlay, and other methods.

During the pilot stage, focus was on evaluating the geological-engineering “dual sweet spots” on the limestone-rich shale oil reservoirs in gentle slope zones and the mixed shale oil reservoirs in steep slope and deep subsag zones. The favorable lithofacies of limestone-rich shale oil reservoirs in gentle slope zones are laminated sparry muddy limestones and cryptocrystalline limy mudstones. The favorable lithofacies of mixed shale oil reservoirs in steep slopes and deep subsag zones are laminated mixed shales. Guided by the theory of shale oil enrichment in continental rift lake basins, and based on systematic cores, core experiments, well logging and mud logging data, a systematic analysis was conducted on the differences in geological and engineering parameters of various layers to clarify the vertical sweet spot distribution in different wells. The core, testing and logging data were comprehensively analyzed, and the differences in key parameters, such as maturity, porosity, brittle minerals, and pressure coefficients in different locations, were clarified for horizontal prediction of sweet spots. Considering the important factors influencing the generation and enrichment of shale oil, geological quality evaluation parameters such as TOC, R_o, porosity, and the total thickness of favorable lithofacies that cover hydrocarbon source rocks, reservoirs, and oil-bearing properties, and engineering quality parameters such as brittleness index, rock mechanics, and interlayer thickness, quantitative evaluation criteria for shale oil sweet spots (Table 3) were constructed. Compared with limestone-rich shale in gentle slope zones, mixed shale in steep slope and deep sag zones has higher maturity and more developed fractures. After sweet spots were selected, fracturing simulations were conducted to analyze the height, length, and stimulated reservoir volume at different target positions to find the most favorable target window location and guide multi-layer well deployment. For example, the quantitative evaluation criteria of shale oil sweet spots were utilized in NY1-3HF horizontal well deployment in the Niuzhuang Sag. The actual drilling length of the horizontal well was 2 425 m, and the drill-in ratio of Category I sweet spots was 100%. 78 649 m³ of fracturing fluid and 4 667.2 m³ of proppants were injected. The well had worked for 644 d by April 6, 2024, and produced cumulative oil of 3.59×10⁴ t. It’s a good production result.

Using horizontal wells to develop shale oil in the Jiyang Depression is still in a test phase. The well location plan underwent two stages: single-layer development and multi-layer three-dimensional development. The FYP-1 well group adopted single-layer development to avoid pressure channeling and reduce interference between wells, with a well spacing of 380-500 m and a horizontal section length of 2 000 m. Then, to increase the reserves controlled by well group, a multi-layer three-dimensional staggered well pattern was used for the test well group in the Niuye 1 Block, with a well spacing of 300-410 m and a horizontal section length of 2 000-3 000 m.

To explore the best horizontal well pattern for shale oil, after making a breakthrough to single well production, a planar single-layer pilot was conducted on the FYP-1 well group in the Boxing Sag, the Jiyang Depression. Fracturing parameters and fracture monitoring results of multiple fractured wells were analyzed, and the relationship between fracturing scale and fluid volume injected into a section was established. It is found that the fracture half-length first increased and then became gradually stable as more fracturing fluid was injected, and then the increase in the fracture half-length slowed down when it exceeded 200 m, indicating that the fracture propagation ability was limited to a certain extent. By referring to the shale oil and gas development practices in North America, the horizontal well spacing was designed to be twice the fracture half-length monitored by microseismic survey. Simulation results (Fig. 1) indicate that a well spacing of 400 m to 450 m is the best spacing that can ensure high producing inter-well reserves and suppress pressure interference.

The faults and fractures of different scales were comprehensively considered in the FYP-1 well group, the first pilot well group where the fault system is complex. Then, five horizontal wells were deployed in the C5 layer, and the well spacings were 380, 450 and 500 m. The rationality of well spacing was tested by monitoring the interference between wells during fracturing operations. Microseismic and tracer monitoring indicated that the inter-well fracture intersection was not prominent, and the interference was mainly due to pressure transmission, with a relatively small proportion of fluid channeling interference caused by natural fractures. At 2.7 m³/m to 3.2 m³/m of proppants and 45.5 m³/m to 52.0 m³/m of fracturing fluid, the average fracture length was 329 m, indicating some zones were not fractured among the wells. The result demonstrated that a well spacing of 380 m to 500 m was too large under the current fracturing parameters. As there are differences between the model parameters (natural fracture density, distribution, etc.) and the actual geological conditions, and the influence of well interference on fracture propagation was not fully considered, the practical results were not completely consistent with the simulation results. In the future, it is necessary to refine the geological model and improve the simulation method for fracture propagation.

Based on the successful development of multiple horizontal wells in a single pay zone, considering the large vertical thickness and multiple favorable lithofacies, a multi-layer development experiment was carried out in the Niuzhuang Sag to explore how to control more reserves of shale oil. Fracturing physical simulation, numerical simulation, and fracture monitoring have shown that major fractures extended vertically to the maximum height at the perforation point, and fracture height rapidly decreased at places away from the perforation point. It is comprehensively believed that the fracture morphology perpendicular to the horizontal wellbore exhibits a “rhombic” shape. Based on the geological characteristics and production performance in the study area, two well patterns were designed through fracture simulation and reservoir numerical simulation: a direct well pattern and a staggered well pattern (Fig. 2). The results indicate that the staggered well pattern has a long stable production period and high cumulative oil production because of higher producing reserves among wells. The direct well pattern exhibits stronger interferences among wells in different rows, resulting in lower producing reserves, a shorter stable production period and lower cumulative oil production than the staggered well pattern.

A certain degree of fracturing impact and pressure interference exists among wells, but this does not necessarily indicate well-to-well interference during oil well production. Based on the microseismic monitoring, production performance, reservoir numerical simulation, and reservoir engineering method related to NY1-3HF in the Niuzhuang Sag, the produced reserve was calculated after fracturing. The results indicate that there are three flow regions during horizontal well development, namely, an easy flow zone, a slow flow zone, and a stagnant flow zone. In the early stage of production, oil and gas mainly originated from the artificial fracture network, when flow resistance is low, and production is high, but production quickly declines. This region is defined as an “easy flow zone”. The pressure within the artificial fracture network gradually declines as development progresses, and the matrix begins to supply oil to the network. However, the fluid supply speed is slow due to the extremely low matrix permeability, and this region is defined as a “slow flow zone”. The total oil production contribution from the easy flow zone and the slow flow zone accounts for approximately 98%. The outer radius of the slow flow zone approaches to the limit drainage radius, which can be determined through transient production analysis based on early production data from producing wells. The zone where shale oil doesn’t flow is referred to as a “stagnant flow zone”. Fracturing simulation results indicate that, the frequency of pressure channeling is 64% to 83% when well spacing ranges from 200 m to 300 m, indicating severe pressure channeling. The existence of a stagnant flow zone between two wells can prevent pressure channeling but results in less producing reserve. They may decrease by 9 to 21 percentage points when the stagnant flow zone is between 30 m and 80 m. The well spacing should match with the artificial well pattern and the artificial fracture network when producing multiple layers at the same time. The goal of “connecting but not channeling” was achieved by optimizing well pattern, spacing and fracturing parameters when developing Fuling shale gas. Field data statistics show that fracturing 252 new wells caused 408 interferences to old wells, of which 84% are positive impact, and 2% are negative impact on the old wells in the primary well pattern, and the last 14% no impact ^[42].

If the slow flow zones between wells overlap, the goal of “connecting but not channeling” can be achieved. This is the key to the optimization of the well spacing for Jiyang shale oil. Field statistics indicate that the limit drainage radius for matrix shale is 155 m, 180 m for laminated shale, and 205 m for naturally fractured shale. Under current fracturing conditions, comprehensive optimization can determine reasonable parameters such as well spacing and layer spacing for different shales, as shown in Table 4.

Most target shale oil reservoirs are distributed in Es₃^L and Es₄ in the Jiyang Depression. The pressure in and above the middle submember of the 3^rd Member of the Eocene Shahejie Formation (Es₃^M) is normal, and the bearing capacity has an equivalent density of 1.5-1.6 g/cm³. The pressure gradually increases from Es₃^L, and reaches a coefficient of 1.8 to 2.0 in Es₄^U. Under such conditions, it’s inevitable to encounter upper leakage and lower well kick scenarios if both high and low pressure systems are opened in the same open-hole section. To ensure successful drilling, a technical casing must be installed in the horizontal section when the drilling fluid density is over 1.6 g/cm³, and the installing depth shall exceed the low-pressure layers in and above Es₃^M. This can prevent simultaneous occurrence of well kick and leakage when drilling the third section. Based on the selected three-section well structure, a well-adapted well structure series were established by comprehensively considering the well construction cycle and the need for fracturing stimulation and optimizing the bit and casing series (Table 6).

Take the Minfeng Sag as an example. The formation pressure curve in the target block was established based on logging data, fracturing pressure experiments, and actual drilling data. The mechanical equilibrium to avoid well kick, lost circulation, collapse and stuck pipe in the open- hole section was analyzed. The technical casing was calculated to be set at approximately 3 150 m and the well could be completed in Es₃^M by using a bottom-up well structure design method. The final well structure is:

The first spud section is Φ444.5 mm×Φ339.7 mm, at a vertical depth of 400 m. The second spud section is Φ311.2 mm×Φ244.5 mm, at a vertical depth of 3 150 m. The third spud section is Φ215.9 mm×Φ139.7 mm, and the cement returned to the wellhead.

In early drilling operation, the Φ311.2 mm borehole in the second section encountered challenges such as difficult direction with PDC bits, low ROP, and a short service life of roller cone bits, so that a well would be finished only after three to four trips. After optimizing well trajectory and bit, a well in the pilot group in the Niuye 1 Block could be finished by two-trip in the second spud section. After taking a series of measures on the bit, screw and hydro-oscillator, drilling parameters, well trajectory, and high-performance drilling equipment, a well in the pilot group in the Minfeng Sag could be finished by one-trip in the second spud section. Multiple rounds of technological iteration and improvements have helped reduce trips in the second spud section with large boreholes of directional wells with three-section structures, and initially, a one-trip drilling technology was established in the second spud section.

The focus was shifted to improving drilling efficiency after “achievable drilling”. Severe hydration and mud- making may easily make drilling tools packed, stuck and jammed, and it is difficult to control rheological properties in the upper shale oil reservoirs in Jiyang continental rift lake basin. These issues may result in excessively thick mud cakes and poor borehole cleaning. Additionally, there are risks of high-viscosity oil invasion and wellbore collapse when drilling at high temperature and high pressure. Conventional water-based drilling fluid systems cannot meet the requirements of drilling horizontal shale oil wells.

Innovative approaches were employed, including the utilization of Ca²⁺ and Na⁺ to reduce water activity and increase osmotic pressure. Additionally, K⁺ was used to limit swelling and separation to ensure strong inhibition properties of drilling fluid while keeping the borehole clean. This approach is effective in reducing short trips and gauge reaming, resulting in more regular wellbores and higher cementing quality. According to the reservoir characteristics, mud-making capacity, formation water type and activity, over 200 sets of inhibition and rheological evaluation experiments were conducted. By considering rock-carrying effects, the inhibition properties of drilling fluid were enhanced through synergistic application of macromolecular polymers, amine-based polyols, and inorganic salts. These optimization efforts have promoted to establish water-based drilling fluid systems suitable for different blocks (Table 7).

In early drilling operations, diesel-based drilling fluid induced several problems, such as low flash point, high volatility, significant harm to human health, large drilling fluid loss, poor resistance to high-pour-point oil contamination, and difficulty in controlling rheological properties. In addition, suction often led to hard well control and wellbore instability during tripping. To cope with these challenges, a low-relative-molecular-weight synthetic base was developed. This base fluid composed of low-carbon hydrocarbons is featured by a highly branched structure of isoparaffins. It boasts of a high ignition point, a low pour point, environmental friendliness, low viscosity, excellent low-temperature fluidity and high-temperature stability. To tackle the problems of high-temperature and high-pour-point oil invasion and poor wellbore stability, a low-clay-content synthetic drilling fluid system was formulated using the base fluid. It can increase displacement and ROP and keep borehole clean. This system is further enhanced with high-temperature-resistant emulsifiers, dispersive viscosity reducers, and multi-scale sealing agents (Table 7). The system can work at high temperature up to 230 °C, severe crude oil invasion up to 20%, and high formation pressure up to 7 MPa. As a result, wellbore stability and drilling safety are highly enhanced, which shortens the drilling cycle of the third spud section by 35%. However, compared with foreign technologies, the low-viscosity synthetic drilling fluid requires further testing.

Jiyang shale oil reservoirs are generally over 3 500 m deep, and characterized by poor physical properties, complex lithology and strong plasticity, so it is difficult to fracture. In early exploration and development, conventional volume fracturing operation failed to inject fracturing fluid at a scale of 10 000 cubic meters and proppants at a scale of 1 000 cubic meters. The flow conductivity of the induced fracture network was insufficient to meet the requirement of economical and efficient production. For example, the shale oil production from Well B1H dropped from a peak of 8.22 t/d to less than 1.00 t/d within one month after fracturing, and challenges in difficult fracturing, insufficient support, small SRV, and low productivity were outstanding.

To cope with challenges in poor physical properties and difficult fracturing, a new high-conductivity fracture network fracturing technology featured by CO₂+acid, variable viscosity fracturing fluid, and pulse adding sand to major fractures to reduce fracturing pressure and promote fracture propagation was developed for the shale oil reservoirs in the Jiyang Depression.

A complex fracturing fluid injection mode was proposed, which is featured by using CO₂ and acid to reduce fracturing pressure and promote fracture propagation, and injecting low-viscosity fracturing fluid, followed by high-viscosity fracturing fluid. Laboratory experiments have shown that supercritical CO₂ soaking can reduce the shale fracturing strength by 9% to 20%. Field fracturing practices have demonstrated that the reservoir breakdown pressure could be reduced by 19 MPa after injecting 200 t of CO₂ and 30 m³ of low-viscosity acid fluid. Simulation of fracture propagation by CO₂-energized fracturing revealed that the density of the fracture network increased from 0.06 fractures/m to 0.13 fractures/m when the proportion of pre-injected CO₂ increased from 10% to 30%, representing a 117% increase. CO₂ is effective to improve fracturing stimulation. Pre-injecting CO₂ fracturing technology has been applied in 69 horizontal wells in shale oil reservoirs.

A combination of emulsion-type thickener and synergists was employed to enhance the viscoelasticity and temperature resistance of fracturing fluid for achieving intermolecular self-assembly and interpenetration. This process allows the attraction between anions and cations to form ionic bonds, facilitating viscosity enhancement. The composite fluid exhibits excellent temperature and shear resistance even at a low dosage. The fracturing fluid formulated with a 1.2% mass fraction composite fluid, maintained a viscosity greater than 40 mPa·s when tested at 160 °C and a shear rate of 170 s⁻¹ for 2 h. Additionally, this fracturing fluid possesses a superior sand-carrying capacity. The proppant settlement rate is only 3.6×10^-4 mm/s over 24 h, as evidenced by static sand-carrying experiment.

In terms of proppants, considering a complex fracture network system consisting of self-supporting fractures, branch fractures and major fractures, a study on fracture conductivity simulation revealed that using quartz sands with equal particles ranging from 0.212-0.380 mm (40-70 mesh) + 0.150-0.212 mm (70-120 mesh) + 0.109-0.150 mm (100-140 mesh) instead of 0.109-0.212 mm (70-140 mesh) can enhance the migration and effective support of proppants in branch fractures, and induce staggered filling in remote self-supporting fractures. Quartz sands replaced ceramic proppants entirely in Well NY1-2HF. Specifically, 0.109-0.150 mm (100-140 mesh) quartz sands were used to reduce filtration and pressure, and modify fracture morphology. 0.150-0.212 mm (70-120 mesh) quartz sand supported the major fractures, while 0.212-0.380 mm (40-70 mesh) quartz sand supported the fracture mouth and near-wellbore fractures. This approach improved the placement height and supporting distance of proppants, resulting in an increase of over 30% in the effective support volume of the branch fracture network. This operation achieved multi-level support for induced fractures. Stimulated by the fracture network fracturing technology and producing through an 8 mm choke, the oil production from Well FYP1 was at most 171 t/d during the production test.

With the deepening of shale oil exploration and development in the Jiyang Depression, some early problems were found, such as excessively large fracture spacing and inadequate produced reserves among fractures. In the early stages, the fracture spacings were generally larger than 50 m, resulting in low “fracture-controlled reserves”, and not very effective fracture propagation through most perforation clusters, and consequently poorer fracture complexity and less produced reserves between fractures. According to the characteristics of the shale oil reservoirs in the Jiyang Depression, a dynamic propagation model for multiple fractures by dense cutting volume fracturing in horizontal wells was established using the finite element method. Numerical simulation was conducted to study the effects of induced stress difference, net pressure, and fracture width on interference between fractures. Key fracturing parameters were optimized, including but not limited to the number of perforation clusters per section, cluster spacing, and fracturing operation scale, which formed a dense cutting volume fracturing parameters chart (Fig. 4). Based on the simulation method for hydraulic fractures in bedding-rich shale, the cluster spacing was reduced from the initial tens of meters to 8-12 m, and the number of perforation clusters per section was increased from the original 2-3 clusters to 5-9 clusters, in order to minimize the negative impact of stress interference and maximize stimulated reservoir volume. It is also considered balanced stimulation for bedding-rich shale layers.

The temporary plugging and diverting technology was used to improve the uniformity of reservoir stimulation by addressing the severe non-uniform propagation of multiple clusters of fractures. Field practices showed that without temporary plugging, the propagation of the middle clusters of fractures was limited, resulting in inadequate stimulation. After implementing temporary plugging, fracture propagation was relatively balanced, and the drainage area of the fractured zone increased (Fig. 5). Rope knots and flexible plugging agents were used in the Jiyang Depression. The plugging pressure could be over 11 MPa. The “dense cutting volume fracturing + temporary plugging” technology changes fracturing process from “fracturing reservoir” to “crushing reservoir”, and increases SRV from 1 312×10⁴ m³ to 1 710×10⁴ m³ in a well.

By fully utilizing the stress field induced by fractures, the reserves in the zones between clusters that have not been sufficiently stimulated could be effectively produced, and consequently increasing well-controlled reserves and recoverable reserves. Simulation to stress interference between fractures at different cluster spacings indicates that a small cluster spacing may cause high stress inter-ference. The fractures would expand unevenly due to the stress interference when the cluster spacing is less than 5 m (without initiation in the middle part or limited fracture length), while the stress interference is relatively low when the cluster spacing is 10 m to 14 m. The downward trend of stress interference is gradually gentle as the cluster spacing increases. Based on a comprehensive analysis of fracture propagation, competitive diversion, stress interference, and operating pressures at different spacings, combined with optimization of limited entry perforation and uneven distribution of fractures, the cluster spacing could be reduced to 4 m to 7 m.

Since a long horizontal section may encounter strong reservoir heterogeneity (i.e., the cluster stress difference ranges from 1 MPa to 3 MPa), the initiation and propagation of multiple fractures are uneven. Based on the difference in reservoir mechanical properties, the difference in shothole diversion was investigated at heels and toes at various fracture spacings. An optimal design method was established for coupled and unevenly spaced fractures under different cluster spacings and hole conditions, achieving the goal of balancing the pressure difference within fractures and ensuring balanced diversion among clusters. The horizontal principal stress in the horizontal section was calculated through logging data and geostress formula, and the number of shotholes was optimized accordingly. The results show that the number of shotholes could be reduced for clusters with low stress (to a minimum of 4), while the number of shotholes should be increased for clusters with high stress (to a maximum of 8). This differentiated clustering approach can significantly improve the efficiency of shotholes. In Well FY1-2HF, on the same fracturing stimulation scale, the extremely limited entry dense cutting volume fracturing technology was used, and the cluster spacing was reduced from 8 m to 12 m to 4 m to 7 m. As a result, the SRV per section increased from (20-35) × 10⁴ m³ to (50-70) × 10⁴ m³, the fracturing cost per section reduced by 30%, and the recoverable reserves per well increased by 25%, demonstrating a significant improvement in stimulation effect.

After three rounds of fracturing technology iteration, the volume fracturing technology changed toward enhanced stimulation. However, casing damage and deformation gradually emerged during initial fracturing in the pilot well group, and 8 of 100 sections were deformed (Table 11). Engineering parameters were optimized based on magnetic signals and tension warnings to protect wellbore safety and change inter-well fractures from intersecting to critically contacting. Finally, the number of deformed sections reduced to four of 100 sections.

To get wellbore safety and maximum SRV, fracturing stimulation was conducted with the help of an early warning system and an optimized operation mode which is “multi-well zipper fracturing” developed on “double- well zipper fracturing”. Inter-well interference and stress focus became less (Fig. 6). By fully using superposition effect, and optimal fracturing scale and parameters, the fracture-controlled reservoir volume reached the maximum, and deformed sections reduced to 0.8 per 100 sections while getting safe stimulation.

The shale oil development in the Jiyang continental rift lake basin has undergone multiple iterations and upgrades in terms of development, drilling and fracturing technologies. Production increased rapidly after single well evaluation and pilot well group, and the initial development result is satisfactory. In 2023, the new production capacity was 30 × 10⁴ t, yearly oil production was 32.8 × 10⁴ t and cumulative oil production was 53.2 × 10⁴ t. By December 31, 2023, 64 horizontal wells had been put into production, and the oil production was 1 363 t/d and the water cut was 66.2%. Through multiple technological iterations, the investment per exploration and evaluation well has been reduced by 35%, and the investment per pilot well group has been further reduced.