Tight reservoirs commonly exhibit low permeability and pronounced lithological heterogeneity, resulting in complex interactions among far-field stress, local structural weakness, and fluid-driven fracture propagation. In this study, four non-replicated 2 m × 2 m × 1 m physical-model specimens representing tight glutenite, tight sandstone, and No. 3 coal rock from the Huabei Oilfield were investigated using an ultra-large true-triaxial hydraulic-fracturing system. Surface-fracture observations, microseismic monitoring, and high-frequency wellhead-pressure measurements were integrated to compare fracture responses under lithology-specific combinations of injection rate, fluid viscosity, perforation configuration, and stress state. The tested glutenite cases exhibited branched or localized fracture patterns depending on the combined treatment configuration; the sandstone case was dominated by a throughgoing main fracture approximately aligned with the principal-stress direction; and the coal-rock case showed extensive participation of bedding and cleat systems. These morphological differences were accompanied by distinct pressure and microseismic signatures, indicating different pathways of hydraulic-energy redistribution and fracture activation. For the two glutenite cases, the combined change from a single-perforation configuration at 0.5 m3/min to three helical perforations at 120° and 0.7 m3/min was associated with a 42.2% larger microseismic-derived stimulated reservoir volume (SRV). Taken together, these responses indicate a shift from stronger far-field-stress-controlled localization in the comparatively uniform sandstone to progressively greater local structural control by heterogeneous interfaces in glutenite and by bedding/cleat discontinuities in coal rock. Because each configuration was represented by a single specimen and several experimental variables changed simultaneously among cases, the observed differences are interpreted as case-specific mechanistic trends rather than statistically established universal relationships. The results show the value of combining fracture morphology, microseismic spatial evolution, and pressure dynamics for interpreting lithology-dependent fracture propagation in ultra-large physical models and for developing qualitative, lithology-adapted hydraulic-fracturing concepts.

Horizontal wells provide a significantly larger drainage area than vertical wells, offering substantial production advantages. However, pronounced reservoir heterogeneity poses significant challenges to effective acid placement. Considering the current development status of the main upper formations in the Ahdeb oilfield, this study systematically analyzes the key technical difficulties in acid stimulation for horizontal wells and proposes a targeted acidizing strategy. The application of coiled tubing hydraulic jet acidizing technology, integrated with a spindle-shaped acid distribution method, enabled precise targeting. An operational design chart was developed to determine the required injection rates and surface pressures for various nozzle configurations (number and diameter), thereby facilitating optimized treatment design. Field application results demonstrated that post-stimulation production rates increased to 3.8–8.4 times the pre-treatment levels, confirming the significant enhancement of horizontal well stimulation achievable with targeted acidizing technology.

Aiming at unclear imbibition replacement mechanisms and flowback/production strategies in unconventional reservoirs of the Erlian Block, this study proposes a systematic approach integrating “imbibition-flowback-productivity synergy” to optimize post-fracturing shut-in and production regimes. By developing numerical models incorporating geological and engineering factors, we analyzed fluid dynamics during both the shut-in and production phases. Concurrently, crude oil displacement-fracturing fluid imbibition replacement experiments were conducted to guide parameter optimization. The results indicate that optimized shut-in time and production rates substantially increase recovery efficiency while mitigating reservoir damage and proppant flowback. The well shut-in time of the Erlian Block can achieve the optimal shut-in replacement effect in about 20–25 days. The optimized flowback rate of the unconventional reservoir in the Erlian Block is 25–30 m3/d. The findings offer theoretical insights and practical recommendations for the efficient development of unconventional resources.

Hydraulic fracturing technology significantly enhances reservoir conductivity by creating artificial fractures, serving as a crucial means for the economically viable development of low-permeability reservoirs. Accurate prediction of post-fracturing productivity is essential for optimizing fracturing parameter design and establishing scientific production strategies. However, current limitations in understanding post-fracturing production dynamics and the lack of efficient prediction methods severely constrain the evaluation of fracturing effectiveness and the adjustment of development plans. This study proposes a machine learning-based method for predicting post-fracturing productivity in multi-layer commingled production wells and validates its effectiveness using a key block from the PetroChina North China Huabei Oilfield Company. During the data preprocessing stage, the three-sigma rule, median absolute deviation, and density-based spatial clustering of applications with noise were employed to detect outliers, while missing values were imputed using the K-nearest neighbors method. Feature selection was performed using Pearson correlation coefficient and variance inflation factor, resulting in the identification of twelve key parameters as input features. The coefficient of determination served as the evaluation metric, and model hyperparameters were optimized using grid search combined with cross-validation. To address the multi-layer commingled production challenge, seven distinct datasets incorporating production parameters were constructed based on four geological parameter partitioning methods: thickness ratio, porosity–thickness product ratio, permeability–thickness product ratio, and porosity–permeability–thickness product ratio. Twelve machine learning models were then applied for training. Through comparative analysis, the most suitable productivity prediction model for the block was selected, and the block’s productivity patterns were revealed. The results show that after training with block-partitioned data, the accuracy of all models has improved; further stratigraphic subdivision based on block partitioning has led the models to reach peak performance. However, data volume is a critical limiting factor—for blocks with insufficient data, stratigraphic subdivision instead results in a decline in prediction performance.

Well-production forecasting plays a crucial role in oil and gas development. Traditional methods, such as numerical simulations, require substantial computational effort, while empirical models tend to exhibit poor accuracy. To address these issues, machine learning, a widely adopted artificial intelligence approach, is employed to develop production forecasting models in order to enhance the accuracy of oil and gas well-production predictions. This research focuses on the geological, engineering, and production data of 435 fracturing wells in the North China Oilfield. First, outliers were detected, and missing values were handled using the mean imputation and nearest neighbor methods. Subsequently, Pearson correlation coefficients were utilized to eliminate linearly irrelevant features and optimize the dataset. By calculating the gray correlation degrees, maximum mutual information, feature importance, and Shapley additive explanation (SHAP) values, an in-depth analysis of various dominant factors was conducted. To further assess the importance of these factors, the entropy weight method was employed. Ultimately, 19 features that were highly correlated with the target variable were successfully screened as inputs for subsequent models. Based on the AutoGluon framework, model training was conducted using 5-fold cross-validation combined with bagging and stacking techniques. The training results show that the model achieved an R2 of 0.79 on the training set, indicating good fitting ability. This study offers a promising approach for the development of oil and gas production forecasting models.

In this study, the performance of water-based fracturing fluids and supercritical CO2 in three types of representative reservoirs (sandstone, conglomerate, and shale) was investigated. The results showed that there are differences in fracture initiation pressures in different rocks, but the fracture initiation pressure of supercritical CO2 is lower than that of water regardless of the rock type. In sandstone reservoirs, supercritical CO2 induced more complex fractures than water, resulting in branching fractures. In conglomerate reservoirs, hydraulic fractures pass through the conglomerate and are flatter, whereas supercritical CO2 fractures pass through or around the conglomerate, and thus the fractures are more tortuous. Gravel stopped the fracture extension in both conditions. In shale reservoirs, supercritical CO2 can communicate natural fractures more effectively than water, thereby increasing the effective transformation volume. The study provides theoretical guidance for reservoir adaptation of supercritical CO2 fracturing.

Hydraulic fracturing is one of the core technologies for unconventional gas reservoir development. This technology injects proppant into artificial fractures to form support channels with large displacement, thereby improving reservoir conductivity and increasing single well production. However, with the increase of the construction displacement, the friction of the fracturing fluid string will greatly increase, which greatly limits the scale of reservoir stimulation. Practice shows that the annular fracturing process can effectively reduce the friction along the pipe string. The friction resistance along the fracturing string is calculated by the formula of drag reduction ratio. According to the measured friction resistance data of fracturing construction in the western area of Sulige gas field, and modifying some coefficients of the formula of drag reduction ratio, the calculation formula of annular fracturing string friction is suitable for the western area of Sulige gas field. At the same time, based on the construction data after temporary plugging and diverting fracturing in Well X in the west area, the friction resistance of the fracturing string after temporary plugging is calculated, and the influence process of displacement and sand concentration on the friction resistance is quantitatively described. This process can effectively reduce the construction friction resistance, increase the construction displacement and expand the scale of fracturing reconstruction.

The evaluation and management of the annulus pressure in the injection-production well of the gas storage is an important part of the wellbore integrity of the injection-production well. The Suqiao gas storage has experienced seven complete injection and production cycles. The production method puts high demands on the integrity of the injection-production well. At present, the injection and production wells of Suqiao Gas Storage in North China have different degrees of pressure in the oil casing annulus, which seriously threatens the safety of the wellbore of the gas storage. This paper analyzes the annulus pressure situation through different injection-production stages and different working conditions of gas storage injection and production wells, and establishes the environment by combining APIRP-2, NORSOK, ISO/TS 16530-2, SY/T5724—2008 and other standards. An annulus pressure evaluation process and an annulus pressure risk evaluation system that combines static and dynamic conditions. A four-level risk control model for gas storage injection and production wells is proposed. Annulus pressure well production management methods have been formulated to continuously improve gas storage. The operating environment and the treatment of injection-production wells with annulus pressure exceeding the maximum allowable value, especially the annulus blow-by problem of Well Su-20K-P1. The annulus pressure treatment has been carried out to achieve effective plugging and ensure the injection and production. The wellbore integrity has achieved a good repair effect, which has certain guiding significance for the evaluation of the wellbore integrity of the gas storage injection and production wells and the treatment of annulus with pressure.

The high viscosity of heavy oil makes it difficult to realize its economic value. Therefore, improving the fluidity of heavy oil can effectively improve the economic benefit of the development of heavy oil resources. Oil-soluble viscosity reducers can utilize functional groups in monomers to break up asphaltene aggregates to improve the flow of crude oil. Graphene can be used to insert and split asphaltene aggregates through sliding phenomena and π–π interaction with colloidal asphaltene, thereby improving the fluidity of heavy oil. In this study, a graphene nanocomposite viscosity reducer was synthesized from lipophilic-modified graphene and a polymer viscosity reducer. The net viscosity reduction rate reached 80.0% at 400 ppm. Compared with a polymer viscosity reducer, the viscosity reduction effect of a graphene nanocomposite viscosity reducer was improved by about 7%. Structural characterization of a graphene nanocomposite viscosity reducer was characterized with infrared spectroscopy and a thermogravimetric test. The mechanism of a graphene nanocomposite viscosity reducer splitting asphaltene aggregates was verified with scanning electron microscopy. This study provides a theoretical and practical basis for the research and development of a novel nanocomposite viscosity reducer.

Huabei Oilfield Jin 45 fault block Es2 is a middle porosity and low permeability reservoir with only 1.7% recovery, which has great potential. Horizontal well technology is an effective way to exploit old low permeability oil fields. It is proposed that the remaining oil enrichment area of Jin 45 fault block can be exploited efficiently by “horizontal well + staged fracturing”, and the utilization degree of difficultly-recoverable reserves can be improved. In the actual development, how to enlarge the reformation volume, realize the full reformation of the horizontal section and avoid the rapid connection with the water injection well has become the main technical problems. Based on the integrated evaluation and analysis of “geology-reservoir-engineering” in Jin 45 fault block, the spatial distribution technology of non-equal-length fractures in horizontal wells is formed to achieve the optimal match between artificial fractures and well pattern. The integrated fracturing design technology of “reservoir-engineering” was put forward. The fracturing technology of “pumping bridge plug + multi-cluster perforation”, combined with temporary plugging agent technology, has realized the fracturing of close cut volume fracture network. The horizontal well of Jin 45 fault block has formed a series of main reformation technology of “non-uniform fracture distribution + temporary plugging and diversion + multi-stage fracturing” By the end of 2020, three horizontal Wells have been fractured in the Jin 45 fault block, with a total of 46 clusters in 18 stages. The maximum daily oil production of a single well is over 40 tons, which is the highest of single horizontal well production in central Hebei region, providing a guarantee for the production capacity construction and recovery improvement of Jin 45 fault block, and providing technical support for the construction of relevant blocks in Huabei Oilfield.

The upper layer of Oil field A is developed by horizontal linear well pattern with long well segment. After completion, there is relatively serious formation damage, and the tested epidermal factor is up to 6.21 on average. Due to the length of horizontal well section and the serious vertical heterogeneity of formation, some strata were over-acidized in the early stage, so it was very difficult to distribute acid evenly. For this reason, the low contribution layer of horizontal section was determined by using amino carboxylic acid system and coiled tubing hydrojet acidification process, combined with reservoir characteristics, and the spindle-type acid distribution method was adopted to optimize nozzle combination parameters to predict construction displacement and ground construction pressure. The laboratory experiment was carried out to compare with the conventional acid system for core displacement experiment. The acid could form acid-etch wormhole, effectively extend the acid-action distance, and achieve the purpose of slow and deep penetration.

A novel hydrophobically associating polymer (HHA-RPM) was synthesized by a solution polymerization method with a modified acrylamide (AM) as the main component and implanting an anionic group. The static adsorptivity of the polymer was measured by an ultraviolet visible light photometer with an adsorption amount of about 11.0 mg/g. The influence of concentration, temperature and salinity on the apparent viscosity of the polymer solution system was investigated indoorally, and the HHA-RPM system was prepared. In view of the on-site requirements for the timeliness of the phase permeability improver, an antioxidant was added to the system to evaluate the durability of the HHA-RPM system.

The acidification technology is an important measure to increase the production and increase the injection of oil and water wells. However, due to the complicated working conditions of the acidification measures and the difficulty in determining the construction parameters, it is necessary to establish the acidification model of the injection wells and optimize the parameters. The paper uses the grey correlation analysis method to find the correlation between each construction parameter and the daily injection volume of the injection well, establishes the BP neural network program, trains it according to the existing data and predicts the artificial controllable parameters in turn to find the best construction parameter combination. Taking a single well as an example to predict the parameters and guide the on-site construction. The results show that combining the mathematical method with the acidification construction technology of the injection well and establishing the model prediction parameters can significantly improve the injection efficiency of the injection well.

Over-displacement technology often occurs in the fracturing process of horizontal gas wells. The effect of horizontal shale gas wells productivity with different fracture morphology considering over-displacement were analyzed by numerical simulation. The results show that the over-displacement productivity is only 12.3%-15.0% of the equilibrium displacement productivity considering the complete fracture closure, and the fracture morphology has no effect on the productivity. Therefore, the amount of over-displacement hydrofrac fluid should be minimized in horizontal gas well, the fracturing fluid can rapidly gel-break and flowback after fracturing, proppant can flow back or settle at the fracture seam, and complex fractures can be formed near the wellbore as far as possible, so that it can reduce the impact of over-displacement on productivity. This study can provide a theoretical basis for fracturing design and productivity prediction of horizontal gas wells.

Sandstone reservoirs in Huabei Oilfield are characterized by low porosity, low permeability, high clay content, strong heterogeneity and high reservoir temperature. In order to solve the problems of rapid reaction, short effective penetration distance and secondary precipitation in conventional acid system, a new composite acid system is studied. The experimental results show that the acid-rock reaction speed of the new composite acid system is lower than that of the conventional acid system; the chelating ability of Ca2+, Fe3+ and Mg2+ ions is stronger; the corrosion rate of N80 steel is 1.57g/m2•h, far below the industry standard (10-20g/m2•h); the permeability of the core after acidizing increased by 3.5 times. This new type of composite acid system with slow reaction speed, scale inhibition and deep penetration is of great significance for acidizing low porosity and low permeability sandstone reservoirs in Huabei Oilfield.

In order to screen out the optimal microemulsion oil drive system, the effect of micro emulsion performance on the residual oil of pore is selected, and the remarkable effect of improving recovery rate is proved from both macro and micro aspects by analyzing the fissure core oil drive experiment and the distribution law of the residual oil of the pore. The results showed that the best microemulsion system is made of positive octane 8mL, water 8mL, 4.5% mass fraction of the beetroot, 6% mass score of positive butanol, 5% quality score of NaCI. And that microemulsion system has a smaller particle size distribution range, higher viscosity, strong stability and a smaller proportion of pore residual oil.

Aiming at the problem of shortage of clean water resources and mixing fracturing fluid in winter in Erlian oilfield, the technology of producing water to prepare fracturing fluid was studied. Horizontal comparison of water samples from four combined oil and gas treatment stations shows that oil, surfactant and bacteria are the main factors that affect the indigestion of hydroxypropyl guar gum in oilfield produced water. Through the indoor research developed a new type of multi-functional cosolvent and explored the oilfield produced water confecting fracturing fluid formulation system: 0.3-0.5% hydroxypropyl guar gum +X% multifunctional cosolvent + 0.2% flow-back agent + 0.4-0.6% crosslinking agent. This technology simplifies the mixing process and reduces the amount of additives. The liquid still has a high viscosity after being placed for more than 3 to 4 days in summer. In winter, using the produced water for mixing can reduce the influence of environmental temperature and ensure the smooth construction. After field application in well h5-19, the effect is outstanding, which provides important technical support for follow-up fracturing construction in Erlian oilfield.

In recent years, the measure of fracturing fluid blending was adopted prior to operation. The traditional form of fluid blending not only has the problem of long operation cycle and high strength of fluid blending and so on, but also has difficult disposal of flowback waste fluid and reservoir damage. For avoiding the disadvantages of traditional fluid blending, the online preparation for polymer fracturing fluid (OPPFF) is developed to replace the traditional melon gum system for preparing fracturing fluid continuously on-line. Laboratory e-valuation results show that the viscosity of OPPFF is above 60 mPa.s after 90min shearing at 120 degrees C and 170 s(-1), which could meet the requirements of conventional fracturing. Low molecular polymer emulsion, multifunction additive and ammonium persulfate are pumping into sand blender by metering pump, then mixed with water and propping agent to finish the fluid blending process with 50% sand ratio. It has strengths such as easy preparation, less waste of materials, low reservoir damage and no pollution, and obtains a high efficient and environment protected fracturing operation. The application results are desirable and it has prosperous future for dissemination.

The permeability of sandy conglomerate reservoir in Erlian Basin is low, and its heterogeneity is very strong, and that its connectivity is bad. The shape of hydraulic fracture in sandy conglomerate reservoir is not regular, and a lot of complicated fracture will be forming in the process of fracturing operation. The effect will not be good when applying common fracturing techniques. Aiming at the pay sand characteristic in BA101x reservoir of Baolige Oilfield, we use some technological means to evaluate brittle index and analyze stress profile; we establish fracture design method which suits sandy conglomerate of research area and develop low damage fracturing fluid which has energy storage function. The research achievement is apllyed in BA77-30x well, using fluid 2201m3 and proppant 112m3. The SRV is about 111×104m3. The well produces 258 day and the cumulative production is about 2393t(4.8 times comparing with common fracturing techniques). It is observed that the effect of network fracturing techniques is better than common techniques.