Reservoir Development Research Articles

Research and Performance Evaluation of Environmentally Friendly Shale Inhibitor TIL-NH2 for Shale Gas Horizontal Wells

Wellbore instability caused by hydration during the development of shale gas reservoirs poses significant challenges to drilling engineering. In this study, a novel and environmentally friendly shale inhibitor, TIL-NH2, was synthesized via free radical polymerization using 1-vinylimidazole and N-(2-bromoethyl)-1,3-propanediamine dihydrobromide as the main raw materials. The molecular structure of TIL-NH2 was characterized by infrared spectroscopy and nuclear magnetic resonance. Incorporating imidazole cations and amino bifunctional groups, TIL-NH2 exhibits excellent inhibitory performance and environmental friendliness. Its performance was systematically evaluated through linear swelling tests, shale cuttings rolling recovery tests, permeability recovery experiments, and dynamic adsorption analyses. The results indicate the following: (1) At a concentration of 1.2 wt%, TIL-NH2 reduced the linear swelling height of shale by 65.69%, significantly outperforming traditional inhibitors like KCl and NW-1. (2) Under conditions of 140 °C, the cuttings rolling recovery rate of TIL-NH2 reached 88.12%, demonstrating excellent high-temperature resistance. (3) Permeability recovery experiments showed that at a concentration of 2.0 wt%, TIL-NH2 achieved a permeability recovery rate of 90.58%, effectively mitigating formation damage. (4) Dynamic adsorption experiments indicated that at a concentration of 2.5 wt%, the adsorption capacity tended toward saturation, reaching 26.00 mg/g, demonstrating stable adsorption capability. Additionally, environmental friendliness evaluations revealed that TIL-NH2 has a degradation rate exceeding 90% within 28 days, and its acute toxicity is significantly lower than that of traditional inhibitors like KCl (the LC50 of TIL-NH2 is 1080.3 mg/L, whereas KCl is only 385.4 mg/L). This research provides a high-efficiency and environmentally friendly new inhibitor for green drilling fluid systems in horizontal shale gas wells, offering important references for technological advancements in unconventional energy development.

Study on brittleness characteristics of deep shale: A case study of Lu211 well in the Luzhou block.

Ensuring the sustainability of energy is pivotal for achieving a harmonious balance between environmental conservation and economic growth. The mechanical behavior of deep shale reservoir rocks is intricate, presenting challenges in ascertaining their brittleness characteristics. To address this, the study employed a suite of evaluation techniques, encompassing analyses of stress-strain curve attributes, energy dissipation patterns, and mineral composition profiles. The overarching goal was to delineate the variations in deep shale brittleness as a function of depth. The findings indicate a general trend of decreasing shale brittleness with increasing depth. However, the brittleness indices derived from the three distinct evaluation methods varied, with the mineral composition approach yielding the most scattered results. This disparity underscores the heterogeneity of deep shale, likely due to its varied diagenetic history compared to shallower formations. In response to these observations, the study leveraged the principle of weighted averaging to devise a composite brittleness evaluation method. This innovative approach not only integrates the effects of multiple influencing factors but also accounts for the differential impact and weight of each method on the overall brittleness assessment. By doing so, it offers a more nuanced and holistic understanding of shale brittleness. The paper's exploration of deep shale's brittleness characteristics contributes valuable insights for the exploration and development of deep shale reservoirs, enhancing the strategic and operational frameworks within the energy sector. This comprehensive evaluation method serves as a foundation for more informed decision-making, ensuring that energy extraction is conducted in a manner that is both economically viable and environmentally responsible.

Hydrocarbon Accumulation and Overpressure Evolution of the Ordovician Carbonate Reservoirs in the Tahe Area, Tarim Basin, NW China

The recovery of reservoir paleo-pressure has been a key focus in hydrocarbon accumulation research. The evolution of paleo-pressure in carbonate reservoir rocks has long been a research challenge for researchers. Using the Tahe area in the Tarim Basin as a case study, this paper proposes an idea for studying the paleo-pressure evolution in carbonate rocks through fluid inclusions. A series of methods, including cathodoluminescence, fluid inclusion petrography, laser in situ U–Pb isotope dating, and microthermometry, were employed to determine the stages of hydrocarbon accumulation. Additionally, the paleo-pressure of oil inclusions from different stages has been restored, and the pressure evolution of the Ordovician carbonate reservoirs in the Tahe area was reconstructed. The study identifies four stages of oil charging in Ordovician carbonate reservoirs. The four oil-charging events occurred during the Caledonian (459–450 Ma), Hercynian (320–311 Ma), late Indosinian (227–213 Ma), and Yanshanian (134–117 Ma) periods. The overpressure evolution indicates that the Cambrian source rocks reached the first oil generation peak and started to expel hydrocarbons during the late Caledonian period. Oil mainly migrated vertically along strike-slip faults and accumulated in fracture-cavity karst reservoirs. At the same time, the reservoir pressure increased rapidly. Subsequent tectonic compression caused uplift and erosion, leading to the destruction of the oil reservoirs and a decrease in pressure. During the Hercynian period, hydrocarbons migrated and accumulated in reservoirs, leading to an increase in reservoir pressure. Subsequently, a slight formation uplift occurred, which caused a decrease in pressure. During the late Indosinian period, the third stage of oil accumulation led to an increase in reservoir pressure. Tectonic uplift during the Yanshanian period caused reservoir destruction and adjustment, resulting in a decrease in pressure. Reservoir pressure increased with oil charging during the Yanshanian period. Subsequently, a large number of faults developed in the study area, causing further destruction and re-adjustment of the oil reservoirs, which led to a decrease in pressure to the current state of normal pressure or weak overpressure.

Preparation and Performance Evaluation of CO2 Foam Gel Fracturing Fluid

The utilization of CO2 foam gel fracturing fluid offers several significant advantages, including minimal reservoir damage, reduced water consumption during application, enhanced cleaning efficiency, and additional beneficial properties. However, several current CO2 foam gel fracturing fluid systems face challenges, such as complex preparation processes and insufficient viscosity, which limit their proppant transport capacity. To address these issues, this work develops a novel CO2 foam gel fracturing fluid system characterized by simple preparation and robust foam stability. This system was optimized by incorporating a thickening agent CZJ-1 in conjunction with a foaming agent YFP-1. The results of static sand-carrying experiments indicate that under varying temperatures and sand–fluid ratio conditions, the proppant settling velocity is significantly low. Furthermore, the static sand-carrying capacity of the CO2 foam gel fracturing fluid exceeds that of the base fluid. The stable and dense foam gel effectively encapsulates the proppant, thereby improving sand-carrying capacity. In high-temperature shear tests, conducted at a shear rate of 170 s−1 and a temperature of 110 °C for 90 min, the apparent viscosity of the CO2 foam gel fracturing fluid remained above 20 mPa·s after shear, demonstrating excellent high-temperature shear resistance. This work introduces a novel CO2 foam gel fracturing fluid system that is specifically tailored for low-permeability reservoir fracturing and extraction. The system shows significant promise for the efficient development of low-pressure, low-permeability, and water-sensitive reservoirs, as well as for the effective utilization and sequestration of CO2.

Prediction of Thin Pre-Salt Reservoir in PL Gas Field, Sichuan Basin

In this paper, the reservoir characteristics and favorable exploration zones of Jialingjiang Formation in Triassic Jialingjiang Formation in PL gas field, Sichuan Basin are studied in depth. By means of geophysical processing and prediction techniques such as seismic attribute analysis, inversion and structural interpretation, this paper focuses on the sedimentary facies, structure, fractures, reservoir thickness and physical properties of the porous reservoir in Jialingjiang Formation, in order to define the spatial distribution of the reservoir and the favorable exploration zones. The research results show that the development of Baiyun rock beach facies reservoir in Jiawumember is mainly concentrated in well area JT1-PS7-PY1, where the local deposition thickness increases and it is a favorable tidal beach facies zone. Based on multi-attribute analysis and phase-controlled p-wave velocity inversion, this paper predicts the lithology and gas distribution of carbonate and gypsum rocks in the Jiawu Member, revealing that the reservoir thickness of the Jiawu 1 submember is between 5 and 22 meters, and gradually thinning in the southeast direction. Based on paleogeomorphology analysis and fracture development characteristics, six favorable exploration areas with a total area of 48 square kilometers are selected, and three proposed well locations are proposed, which provide guidance for future exploration evaluation and deployment.

A Study on the Accurate Equation Inversion Method for Uncoupled Interface Parameters of OA Media Considering Initial Stress

Underground media are generally affected by the initial stress of the overlying strata. At the same time, the uncoupled interface is an important influencing factor of seismic response, as well as an essential reservoir environment, reservoir space, and migration channel. It is significant to explore the parameters of the uncoupled interface under stress for identifying oil and gas reservoirs. As an effective means of predicting reservoir physical parameters, pre-stack seismic inversion uses information on uncoupled interface fractures under stress to improve the accuracy of reservoir parameter prediction, overcome the problem of insufficient interface parameter prediction methods, and promote oil and gas reservoir exploration and development. Based on the precise equations for directly characterizing uncoupled interface fracture weakness parameters, this paper uses the ANNI inversion method to realize the nonlinear inversion method of uncoupled interface fracture parameters. The feasibility and practicability of predicting underground medium parameters from seismic response characteristics have been verified through model testing and actual work area application.

Pore-scale modelling of particle migration in loose sandstone

During the development of loose sandstone reservoirs, the issue of production decline and bottomhole pressure reduction caused by particle migration is widespread, directly impacting well productivity. Understanding the mechanism of particle migration in sandstone and determining the main factors affecting this process are crucial for improving oilfield development. This study focuses on an offshore oilfield and utilizes real digital core models constructed through CT scanning technology. Numerical simulations of fluid-solid coupling were conducted using Fluent and EDEM software to establish a coupled particle-oil-water flow model. This model was employed to investigate particle blockage modes and the effects of particle size, concentration, and injection rate on particle migration in the reservoir. The results indicate that particle migration primarily occurs in two blockage modes: pinhole blockage and bridging blockage. In sandstone, particle retention rates are primarily controlled by particle size, with larger pore-to-particle size ratios leading to higher retention rates. Particle concentration and injection rate have relatively minor effects on the final retention rate. As for migration distance, particle size significantly influences migration, with larger pore-to-particle size ratios resulting in shorter migration distances. Under low concentration conditions, concentration has a minimal effect on migration distance. However, as the injection rate increases, migration distance also increases. In summary, this study clarifies the particle migration mechanisms and the key factors controlling migration in sandstone formations, providing valuable theoretical support for oilfield development.

A Review on the Water Invasion Mechanism and Enhanced Gas Recovery Methods in Carbonate Bottom-Water Gas Reservoirs

Carbonate gas reservoirs are crucial in gas field development, with carbonate bottom-water gas reservoirs being a significant subset. However, the development of these reservoirs often faces challenges such as water invasion, leading to a low gas recovery rate. Enhancing gas recovery is a primary goal for researchers in this field. This study provides a systematic review of the mechanisms, identification, and dynamic prediction of water invasion in these gas reservoirs. The technical adaptability and application range of different enhanced recovery methods are summarized, and their application effects are evaluated. The results indicate that carbonate gas reservoirs have diverse types of storage and permeability spaces, with a wide distribution of pore size scales, leading to various types of enclosed gas caused by water invasion. The prediction accuracy of water invasion models for bottom-water gas reservoirs with fractures and vugs is relatively low. Therefore, numerical simulation research on the basis of fine reservoir characterization is the key technology. The control of bottom-water invasion and the rescue measures after the bottom-water invasion are the keys to improving gas recovery, which can be divided into four types: drainage gas recovery, water control production, active drainage, and injection medium. Gas production by drainage is the main technology for improving gas recovery, among which foam drainage is the most widespread. The optimization of development parameters in production by water control has a good effect in the early stages of development. The active drainage technology on the water invasion channel is the bottom-up technology for the effective development of strong water-flooded gas reservoirs. CO2 injection may have great potential to improve the recovery of bottom-water gas reservoirs, which is one of the important research directions under the background of “carbon peaking and carbon neutrality”. The research provides theoretical and technical reference significance for enhanced recovery of carbonate bottom-water gas reservoirs.

Experimental study on CO2 flooding within a fractured low-permeability reservoir: Impact of high injection rate

The rapid decay of reservoir energy in the late development of fractured low-permeability reservoir leads to poor development benefit. Injecting CO2 into such reservoir at high pressure and rate can rapidly replenish reservoir energy and fully utilize the advantages of CO2 flooding, which is an efficient approach for CCUS-EOR. Previous laboratory studies have mainly been conducted under conventional low injection rate, with little discussion on the impact of high injection rate (above 20 times the conventional low injection rate) on CO2 flooding, especially regarding the limited reports on the effect of high injection rate on CO2 flooding within a fractured low-permeability reservoir. In this paper, microscopic visualization and fractured-core experiments of CO2 flooding at different injection rates were conducted. The variations in microscopic displacement front and sweep characteristics under different injection rates were clarified. The influence of CO2 injection rate on the macroscopic and pore scale oil production characteristics in fractured low-permeability cores under different injection modes were analyzed. The results indicate that injection rate significantly influences the microscopic displacement characteristics. The final sweep coefficient at 10 μL/min was 25.07 %, and the pre-breakthrough sweep coefficient accounted for approximately 90 %. While for 200 μL/min, the final sweep coefficient was 34.83 %, and the post-breakthrough sweep coefficient accounted for above 50 %. During CO2 flooding in fractured low-permeability core, the oil production before CO2 channeling dominates the final oil recovery. Compared to 0.1 mL·min−1, oil recovery increases by above 20 % at a CO2 injection rate of 4 mL·min−1 at 6 PV. The high-pressure gradient formed by high injection rate enhances CO2 diffusion, promoting the oil mobilization in near-fracture and deep matrix. And it results to a decrease in the minimum pore scale of oil mobilization. Soaking enhances the interaction between CO2 and oil as well as the fluid exchange between fracture and matrix. It further reduces the minimum pore scale of oil mobilization, and the enhancing effect of soaking gradually strengthens with increasing injection rate. The results can provide theoretical reference for application of CO2 flooding within a fractured low-permeability reservoir.

Mechanical Characterization of Main Minerals in Carbonate Rock at the Micro Scale Based on Nanoindentation

The mechanical characterization of carbonate rock is crucial for the development of a hydrocarbon reservoir and underground gas storage. As a kind of natural composite material, the mechanical properties of carbonate rock exhibit multiscale characteristics. The macroscopic mechanical properties of carbonate rock are determined by the mineral composition and structure at the micro scale. To achieve a mechanical investigation at the micro scale, this study designed a scheme for micromechanical characterization of carbonate rock. First, scanning electron microscope observation and energy dispersive spectroscopy analysis were combined to select the appropriate micromechanical test areas and to identify the mineral types in each area. Second, the selected test area was positioned in the nanoindentation instrument through the comparison of different-type microscopic images. Finally, quasi-static nanoindentation was carried out on the surface of different minerals in the selected test area to obtain quantitative mechanical evaluation results. A typical carbonate rock sample from the Huangcaoxia gas storage was investigated in this study. The experimental results indicated apparent micromechanical heterogeneity in the carbonate rock. The Young’s modulus of pyrite was over 200 GPa, while that of clay minerals was only approximately 50 GPa. In addition, the proposed micromechanical characterization scheme was discussed based on experimental results. For minerals with an unknown Poisson’s ratio, the maximum error introduced by the 0.25 assumption was lower than 15%. To discuss the effectiveness of the nanoindentation results, the characterization abilities constituted by lateral spatial resolution and elastic response depth were analyzed. The analysis results revealed that the nanoindentation measurement of clay was more susceptible to influence by the surrounding environment as compared to other kinds of minerals with the experimental setup in this study. The micromechanical characterization scheme for clay minerals can be optimized in future research. The mechanical data obtained at the micro scale can be used for the interpretation of the macroscopic mechanical features of carbonate rock for the parameter input and validation of mineral-related simulation and for the construction of a mechanical upscaling model.

Simulating Water Invasion Dynamics in Fractured Gas Reservoirs

The Longwangmiao Formation gas reservoir in the Moxi block of the Sichuan Basin is a complex carbonate reservoir characterized by a low porosity and permeability, strong heterogeneity, developed natural fractures, and active water bodies. The existence of natural fractures allows water bodies to easily channel along these fractures, resulting in a more complicated mechanism and dynamic law of gas-well water production, which seriously impacts reservoir development. Therefore, a core-based simulation experiment was designed for oil–water two-phase flow. Three main factors influencing the water production of the gas reservoir, namely fracture permeability, fracture penetration, and water volume multiple, were analyzed using the orthogonal test method. The experimental results showed that the influences of the experimental parameters on the recovery factor and average water production can be ranked as water volume multiple > fracture penetration > fracture permeability, with the influence of the water volume multiple being slightly greater than that of the other two parameters. It provides a certain theoretical basis for water control of the gas reservoir.

A novel nonlinear prestack inversion method based on nutcracker optimization algorithm with high convergence speed

Predicting reservoir parameters with high accuracy is still a crucial work of oil reservoir exploration and development. Due to the limitation of computational efficiency, deterministic methods are primarily used in practical production applications for predicting reservoir parameters. When the nonlinear forward equations are exceptionally complex and the initial model constructed deviates significantly from the true reservoir parameters, deterministic methods may have difficulty obtaining reasonable predictions of reservoir parameters. Compared to deterministic methods, intelligent optimization methods based on nature-inspired metaheuristic algorithms have unique advantages because they do not require derivative information, can achieve global optimization, and have less reliance on initial model. Therefore, they perform better in solving complex nonlinear optimization problems. In this paper, a new intelligent optimization algorithm called Nutcracker Optimization Algorithm (NOA) with a high convergence speed is introduced. By utilizing this optimization algorithm to solve the nonlinear inversion problem constructed by the highly nonlinear exact Zoeppritz equations, we analyze the potential of nonlinear reservoir parameters prediction methods based on intelligent optimization algorithms in practical production applications. The synthetic data test shows that, compared to the classical quantum particle swarm optimization (QPSO) algorithm and the highly-cited whale optimization algorithm (WOA), the prestack nonlinear inversion method based on NOA proposed in this paper ensures high convergence accuracy and exhibits high computational efficiency. It significantly reduces computation time and holds great potential for practical production applications. The field data test shows that the proposed method can rapidly and accurately estimates reservoir parameters, validating the feasibility and effectiveness of the proposed method. This has important theoretical value and practical significance for advancing the application of intelligent optimization algorithms in field reservoir exploration and development.

Hydrogel-forming microarray patches combined with powder-based reservoir for labetalol hydrochloride transdermal delivery.

Hypertension is the most common pregnancy disorder and can lead to life-threatening conditions for both mother and fetus. However, managing this condition with oral and intravenous labetalol can be challenging, highlighting the need for alternative delivery methods. This study presents, for the first time, the development of novel powder-based reservoirs incorporated with hydrogel-forming microarray patches (MAPs) to facilitate the transdermal delivery of labetalol hydrochloride (HCl). A holder, created from poly(propylene) using a 3D printer, was designed to house labetalol HCl powder, which was then combined with hydrogel-forming MAPs. This novel system improved the insertion profile of MAPs into Parafilm® layers and excised full-thickness neonatal porcine skin, achieving up to 85 % of needle height penetration without compromising needle integrity (only 8 % height reduction after applying 32 N of force). The current holder design was able to load 50 mg of labetalol HCl and allowed for single or multiple injections of deionised water to dissolve the powder and facilitate permeation through dermatomed neonatal porcine skin in in vitro studies using a Franz cell setup. The results showed that this powder-based reservoir design delivered labetalol HCl more effectively over 24 h compared to directly compressed tablets. Additionally, poly(vinyl alcohol)/poly(vinyl pyrrolidone)/citric acid-based hydrogel-forming MAPs delivered more labetalol HCl than Gantrez® S-97/poly(ethylene glycol)-based MAPs (9 mg vs. 5 mg) in 24 h. This novel system holds promise for improving the delivery of compounds in a simple manner, though further design modifications for one-step application are needed.

Dynamic constitutive modeling and numerical validation of composite toughened oil well cement for well cementing applications

The mechanical property of cement sheaths is a primary indicator for evaluating the quality of well cementing in oil and gas wells. With the exploration and development of complex reservoirs, higher demands are placed on the mechanical properties and the dynamic constitutive models of oil well cement (OWC). This study modified the strength model based on the original Holmquist-Johnson-Cook (HJC) constitutive model and established a dynamic constitutive model suitable for composite toughened OWC with added styrene-butadiene rubber (SBR)latex and polymer polypropylene fiber (PPF). Mechanical tests were conducted on basic and toughened OWC to determine the model parameters, including uniaxial compression, triaxial compression, brazilian splitting, and split hopkinson pressure bar (SHPB) tests. Then, the parameters of the HJC model were calibrated through numerical simulation. Finally, liquid carbon dioxide phase change blasting (LCPCB) experiments were performed to compare the failure characteristics of the two types of OWC at high strain rates, and numerical simulations were used to verify the effectiveness and accuracy of the improved HJC model parameters. The numerical simulation results of the LCPCB test indicate that the fracture patterns and fracturing effect evaluation coefficient of toughened OWC agree with the experimental results. The improved HJC model can effectively describe the dynamic mechanical behavior of toughened OWC during impact processes and provide valuable parameter references for constitutive models of OWC and theoretical support for optimizing designs of perforation completion and fracturing operations after well cementing.

Preparation of thickened P(AA-AMPS) copolymers by inverse emulsion polymerization and evaluation of fracturing and oil flooding performance

Polymer is an essential type of fracturing fluid. Nevertheless, issues such as slow dissolution, high initial viscosity, and challenges in storage, transportation and operation limit its application. To address these issues, a thickened copolymer P(AA-AMPS) was synthesized by inverse emulsion polymerization using acrylic acid (AA) and 2-acrylamide-2-methylpropanesulfonic acid (AMPS) as the monomers. Three P(AA-AMPS) copolymers were obtained by changing the weight ratio of AA and AMPS monomers. When the weight ratio of AA to AMPS monomers was 8.2:1.8, the P(AA-AMPS) copolymer solution exhibited the best interfacial activity, reducing the oil–water interfacial tension to 3.95 mN m−1. The initial viscosity of the copolymer was only 66 mPa s, but its solution could reach a high viscosity of up to 817 mPa s. P(AA-AMPS) copolymers demonstrated good resistance for temperature and shear. For instance, the viscosity of copolymer solution still remained 300 mPa s with a shear rate of 170 s−1 at 90 °C. Furthermore, P(AA-AMPS) copolymers had excellent gel-breaking capacity, sand suspension stability, wettability and oil displacement ability. Therefore, the integration of fracturing and oil flooding can be realized for the development of low permeability reservoirs by selecting appropriate copolymers. P(AA-AMPS) copolymers would play an important role due to their significant viscosity differences and easy operation on storage, transportation and application.

Optimizing Well Trajectories for Enhanced Oil Production in Naturally Fractured Reservoirs: Integrating Particle Swarm Optimization with an Innovative Semi-Analytical Model Framework

Summary Well trajectory optimization is a crucial component in the drilling engineering of naturally fractured reservoirs. The complex heterogeneity and anisotropy of such reservoirs significantly affect the pressure drop distribution within the well and, consequently, the oil well’s output, impacting the economic benefits of the well. Therefore, optimizing the well segment trajectory is key to efficient reservoir development. However, traditional well trajectory optimization methods primarily focus on geological structures and drilling engineering costs, often overlooking future production benefits of the oil well. This paper proposes a new method that first establishes a semi-analytical production prediction model capable of describing complex well trajectories. Although the semi-analytical model has unique advantages in well trajectory description, it typically treats the reservoir as a homogeneous entity, which complicates handling complex reservoir characteristics. To overcome this limitation, we combined optimization algorithms and neural networks to construct a framework for addressing reservoir heterogeneity (Semianalytical Model Framework for Unconventional Wells in Heterogeneous Reservoirs, USAMF-HR), enhancing the semi-analytical model’s ability to describe reservoir heterogeneity. Building on this framework, we applied the particle swarm optimization (PSO) algorithm and introduced constraints on the rationalization of initial well trajectories, as well as limits on particle movement speed and displacement, with the maximization of net present value (NPV) as the objective function, to optimize well trajectory coordinates. Through specific case analysis, the reasonableness and practicality of this method have been verified. The results show that this method can quickly and effectively plan the optimal well trajectory, significantly increasing productivity while reducing costs.

Experimental Study on Enhanced Oil Recovery of Shallow Super-Heavy Oil in the Late Stage of the Multi-Cycle Huff and Puff Process

The shallow, thin super-heavy oil reservoir demonstrates certain characteristics, such as shallow reservoir depths, low-formation temperature, and high crude oil viscosity at reservoir temperatures. In the current production process, the central area of P601 is undergoing high-frequency huff and puff operations, facing certain problems such as decreasing production, low recovery rates, and rapid depletion of formation pressure. Through physical simulation experiments, the various elements of HDNS-enhanced oil recovery technology were analyzed. Nitrogen plus an oil-soluble viscosity reducer can improve the thermal recovery and development effect of super-heavy oil. With the addition of the viscosity-reducing slug, the recovery rate of steam flooding was 58.61%, which was 23.32% higher than that of pure steam flooding; after adding the 0.8 PV nitrogen slug, the recovery rate increased to 76.48%. With the increased nitrogen injection dosage, the water breakthrough time was extended, the water cut decreased, and the recovery rate increased. Nitrogen also plays a role in profile control and plugging within the reservoir; this function can effectively increase the heating range, increase steam sweep efficiency, and reduce water cut. So, the synergistic effects of steam, nitrogen, and viscosity-reducing agents are good. This technology enhances the development of shallow-layer heavy oil reservoirs, and subsequent development technologies are being compared and studied to ensure the sustainable development of super-heavy oil reservoirs.

Study on microscopic production characteristics of crude oil in tight reservoirs displaced by CO2-assisted fracturing fluid

The CO2-assisted fracturing fluid displacement technology is of great significance for enhancing oil recovery (EOR) of tight reservoirs, while the characteristics and mechanism of microscopic production for CO2-assisted fracturing fluid are still unclear. In this study, the displacement experiments of fracturing fluid and CO2-assisted fracturing fluid were launched with two various methods, the nuclear magnetic resonance technology (NMR) and high-temperature and -pressure visualization system respectively. The experimental results show that crude oil in mesopores and macropores is mainly displaced by fracturing fluids, and the residual oil is mainly retained in micropores and small pores. CO2-assisted fracturing fluid improved the oil recovery of tight reservoirs, with more crude oil recovered from small pores, mesopores and macropores, and less residual oil content in the form of flake and droplet. This study provides a prospective EOR technology for the efficient development of tight reservoirs.

Chlorite-induced porosity evolution in multi-source tight sandstone reservoirs: A case study of the Shaximiao Formation in western Sichuan Basin

Abstract The Jurassic Shaximiao Formation in the Sichuan Basin represents a significant tight gas reservoir, exhibiting marked permeability variations between the southern and northern regions of western Sichuan. This study examines the reservoir characteristics of the Shaximiao Formation, with a focus on the evolution of sandstone porosity under bidirectional provenance conditions and the underlying causes of permeability variations. The insights derived from this research are critical for the effective exploration and development of tight sandstone gas reservoirs. Analysis of core samples and thin sections through X-ray diffraction, cathodoluminescence, scanning electron microscopy, and electron probe microanalysis reveals that the southern region predominantly consists of feldspathic and lithic sandstone, whereas the northern region is characterized by feldspathic lithic and lithic feldspathic sandstone. The average porosity and permeability in the southern region are 10.52% and 0.1334 × 10−3 μm2, respectively, while in the northern region, they are 9.74% and 0.5262 × 10−3 μm2. The primary reservoir spaces are intergranular primary pores and intragranular secondary dissolution pores. Compaction significantly reduces porosity, particularly in the northern region (23.94%) compared to the southern region (22.75%), primarily due to the presence of chlorite coatings. Cementation further reduces porosity, whereas dissolution processes enhance it, elucidating the similar porosity values but differing permeabilities between the regions.

Missing data interpolation in well logs based on generative adversarial network and improved krill herd algorithm

Accurate logging data is crucial in geology and petroleum engineering for tasks such as geological modelling, reservoir simulation, and decision-making regarding well repair, water injection, and oil recovery. However, logging instrument failure occurs due to complex conditions such as high temperature and pressure, resulting in incomplete data and posing challenges for reservoir evaluation and development. The existing interpolation methods are primarily based on statistical and machine learning methods, lacking deep mining of hidden associations between logging items. Aiming at the problem of incomplete well-logging data, an incomplete well-logging data interpolation method based on a generative adversarial network and an improved krill herd algorithm is proposed. The results show that the proposed method has stable interpolation for well-logging data missing with different missing rates and any missing positions. Compared with other GANs (GAN, WGAN, and WGAN-GP), the RMSE of the proposed method is reduced by 57.63%, and the R2 is increased by 7.94%. The proposed method is compared with statistical methods (averaging and cubic spline interpolation) and machine learning methods (k-nearest neighbor, support vector machine, and random forest). The experimental results show that the proposed model has stable reconstruction performance for logging data with different missing rates and any missing positions.