Exploitation Of Reservoirs Research Articles

Preparation of novel polymeric surfactants based on synergistic effects and analysis of the mechanism driving the oil-displacement process and enhanced oil recovery

Polymeric surfactants have been favored by researchers due to their ability to increase the viscosity of the aqueous phase, reduce the viscosity of the oil phase, and avoid the chromatographic separation effects of polymer-surfactant binary combination flooding. However, there is little research into the oil-displacement effect of polymer surfactants, and the mechanism whereby it enhances heavy oil recovery remains unclear. To fill this theoretical gap in the research into the oil-displacement mechanism of polymer surfactants, a novel polymeric surfactant PNBM was prepared using acrylamide, acrylic acid, nonylphenol ethoxylate (NP), and 4-vinylbiphenyl (VB). The chemical structure of PNBM was validated by characterization methods such as 1HNMR, FT-IR spectroscopy and elemental analysis. The mechanism of PNBM for enhancing heavy oil recovery was systematically studied based on the displacement and profile control by thickening, reducing viscosity by emulsification, and peeling of oil films and droplets. Polymeric surfactant PNM containing NP and polymeric surfactant PBM containing VB were used as control groups. Benefiting from the synergistic effect of two viscosity-reducing monomers, PNBM has better oil displacement effect compared to PNM and PBM: (1) a tighter adsorption film can be formed at the water–oil interface due to the good interfacial activity of PNBM, so that the average viscosity reduction rate of PNBM at a low concentration reaches 85.5 %; (2) PNBM can significantly increase the viscosity of aqueous solutions (increasing to 38.2 mPa·s), decrease the water–oil mobility ratio, and expand the swept volume; (3) PNBM can reduce the contact angle of the water phase on the oil-wet surface to 62.8°, supplemented by its good viscoelasticity, thereby improving the oil-washing efficiency. Therefore, under the triple effects of displacement and profile control by thickening, reducing viscosity by emulsification, and peeling of oil films and droplets, PNBM can enhance heavy oil recovery by 17.7 %, significantly improving the beneficial industrial exploitation of heavy oil reservoirs.

Stability mechanism of viscoelastically enhanced surfactant air foam for low permeability reservoir

Polymer has been widely studied as an effective means to improve foam stability in reservoir exploitation. Nevertheless, the deployment of this technology in low-permeability reservoirs may prove challenging and could potentially result in formation damage. The innovation of this study is the utilization of viscoelastic surfactants to create enhanced air foam with wormlike micelles and three-dimensional network structures. This can result in a synergy between the properties of fluidity control and oil washing efficiency, thereby enhancing the strength of the foam. The supramolecular self-assembly property facilitates the injection of the foam into the formation while preserving its original structure and properties, thereby enhancing the stability of the foam and markedly improving the recovery of low permeability reservoirs. The viscoelastically enhanced air foam system is composed of the zwitterionic surfactant erucylamido propyl betaine (EHSB) and the anionic surfactant sodium dodecyl sulfate (SDS), which has been designated EHSB-SDS. The foam performance was evaluated using the Waring Blender method and rheological behavior, with foam fluid viscosity, initial foam volume (V0), half-life for drainage (td) and foam half-life (tf) serving as the evaluation indicators. The influence of temperature, salinity and oil content on foam performance is considered to explore the reservoir adaptability. The dynamic/micro stability, macro rheological properties, interfacial viscoelasticity and Zeta potential of the enhanced air foam system were further studied to clarify the stability mechanism of enhanced air foam system. The td, tf and composite index of EHSB-SDS is 56.6 min, 36 h and 648000 mL·min, respectively. The viscoelastic surfactants form wormlike micelles, which increase the foam solution viscosity. This results in a slow drainage speed and the rupture of the bubbles. The adsorption of surfactant at the gas/liquid interface results in an increase in surface activity, interfacial expansion modulus and zeta potential, which serves to enhance the strength of the liquid film and the electrostatic repulsion among bubbles. These three factors are primarily responsible for the stability of the foam. The research establishes a theoretical basis for the effective development of low permeability reservoirs and new foam flooding technology.

Rapid Monitoring of Aquatic Organism Biodiversity Based on Environmental DNA in a Medium-Sized Reservoir

Environmental DNA (eDNA) has emerged as a highly sensitive and efficient tool for the biomonitoring of aquatic ecosystems. In this study, we investigated fish and benthic species communities using eDNA techniques in a medium-sized reservoir (about 3 square kilometers) in Anhui, China. A total of 12 water samples and 11 sediment samples were analyzed by 12S and 18S primers, respectively. We analyzed the composition of species diversity and the effect of seven environmental factors using the Mantel test. A total of 42 fish taxa were present in the water samples, and 188 benthic taxa in the sediment samples. Species composition was different in disparate stations. We found that water temperature and salinity are pivotal factors influencing the composition of fish communities, while chlorophyll-a is a primary environmental determinant for benthic species assembly structures across different zones. Biodiversity information generated by eDNA techniques can be used to reflect the resource status of this reservoir. The relevant results will provide important scientific reference information for the development and exploitation of medium-sized reservoirs.

Anti-Vibration Method for the Near-Bit Measurement While Drilling of Pneumatic Down-the-Hole Hammer Drilling

Pneumatic down-the-hole (DTH) hammer drilling technology has been used extensively in the fields of heat reservoir exploitation and geological exploration owing to its advantages of high efficiency and low pollution. However, the vibration near the bit is up to 40 g while DTH hammer drilling, which significantly affects the performance and longevity of the near-bit measurement while drilling (MWD). To enhance the environmental adaptability of the near-bit MWD in pneumatic DTH operations, a design method for a vibration-damping system based on the parameter optimization of a non-dominated sorting genetic algorithm II (NSGA-II) is proposed in this study. First, the whole structure of the near-bit MWD is designed, including the MWD sub-shell, sensors, measurement circuits, batteries, and connecting structures (the circuit unit). Secondly, this study analyzes the vibration characteristics of the pneumatic DTH hammer near the bit. According to the damping structure, the vibration response model for the circuit unit and the damping model are established. Thirdly, NSGA-II is employed to optimize the parameters of the damping model in terms of the low-frequency, high-intensity vibration characteristics near the bit in pneumatic DTH operations, thereby devising a damping scheme tailored to the unique conditions of DTH hammer drilling. Finally, vibration experiments were conducted to verify the effectiveness of the vibration-damping device. The experimental results indicate that within the vibration frequency range of 5–20 Hz and vibration level of 10–40 g, the peak attenuation rate of the circuit unit is more than 86.446%, and the improvement rate of the vibration stability of the system is more than 75.214%; the anti-vibration performance of the near-bit MWD system in DTH hammer drilling is improved remarkably. This study provides strong technical support for the stability of MWD equipment under such special working conditions. It has broad engineering application prospects.

Experimental study of foam stability and interfacial behaviour of cellulose nanocrystals-enhanced C22-tailed zwitterionic betaine surfactant

The intrinsic thermodynamic instability of foam systems significantly constrains their effectiveness in enhancing oil and gas recovery from unconventional reservoirs. This study investigated the foam properties and interfacial rheological characteristics of the EDAB/CNC/APG system, analyzing the influence of various factors including temperature, pH, and inorganic salts. The results indicated that the optimal concentration ratio for CNC-surfactant system consists of 0.3 % EDAB, 1.5 % CNC and 0.5 % APG by mass fraction. In this system, the addition of CNC forms a three-dimensional network structure at the gas–liquid continuous interface, significantly extending the drainage half-life of the system. At elevated temperatures, the intense molecular thermal motion disrupts the interactions between CNC and EDAB. This disruption leads to a decrease in surface tension and the viscoelastic modulus of interfacial expansion, resulting in an increase of foam volume but a decline in foam drainage half-life. Foam performance and interfacial rheological characteristics are optimal under neutral pH conditions and manifest higher stability in alkaline conditions compared to acidic conditions. In highly mineralized reservoirs (≥5.0 % salt concentration), inorganic salt ions shield the attraction between CNC and oppositely charged surfactants. This shielding weakens the cross-linking within CNC-surfactant systems, altering the structure of the liquid film interface and causing a sharp decrease in foam half-life. The C22-tailed zwitterionic betaine surfactant EDAB, enhanced by CNC, provides a novel, environmentally friendly, efficient, and safe approach to the exploitation of complex, low-permeability oil and gas reservoirs.

Damage Factors and Protection of Low Permeability Reservoir

With the development of science and technology and the progress of society, people's production level has been significantly improved. In this context, people have also put forward higher requirements for the application and development of technology and processes in various production fields. The relevant construction technology of oilfield enterprises is no exception. Low permeability reservoir occupies a large proportion in China's reservoir resources. However, due to the small pore space and large fluid flow resistance of low permeability reservoir, it is more prone to reservoir damage in the development process, and even causes the reservoir to fail to produce in serious cases. Therefore, research on the potential damage factors and damage mechanism of low permeability reservoir and propose corresponding protection strategies are conducive to improving the development effect of low permeability reservoir. The potential damage factors of low permeability reservoir are systematically analyzed, which is of great significance to guide the efficient exploitation of low permeability reservoir.

Fracture Characterization Via AI‐Assisted Analysis of Temperature Logs

AbstractFractures control fluid flow, mass transport, and heat transfer in a geothermal reservoir. This makes accurate characterization of fracture networks a prerequisite for optimal design and control of a reservoir's exploitation. We develop a deep‐learning procedure to identify fracture locations via interpretation of temporally and spatially continuous downhole temperature measurements. A long short‐term memory fully convolutional network (LSTM‐FCN) is used both to capture long‐term dependencies in sequential temperature data and to distill local features around fractures. A wellbore and fractured‐reservoir thermal model is established to generate temperature data for network training. The trained LSTM‐FCN exhibits a unique ability to detect multiple fractures intersecting a borehole. We use the LSTM‐FCN algorithm to evaluate the effectiveness of different‐stage wellbore temperature measurements on fracture detection in a complex fractured system. Our experiments reveal that the use of various‐stage temperature information as an input feature set improves the robustness of fracture detection to noise interference. This study indicates the practical feasibility of obtaining accurate fracture‐network reconstructions from temperature signals, at reasonable computational cost.

Multi-scale nonlinear reservoir flow simulation based on digital core reconstruction

During the exploitation of oil and gas reservoirs, changes in reservoir physical or fluid properties will lead to alterations in formation seepage capacity, subsequently impacting the productivity of oil and gas wells. Therefore, it is crucial to evaluate the variations in reservoir physical and fluid properties as well as their influence on oil and gas well productivity during reservoir exploitation.It employs a descriptive approach to investigate cross-scale (i.e., micro-scale → small-scale → large-scale) fluid seepage phenomena in water flooding. By leveraging digital core reconstruction technology and focusing on micro-pore network simulation, it establishes an analytical framework for studying cross-scale seepage fields, facilitating the exploration of the micro-seepage mechanism that governs non-homogeneous water flooding's impact on liquid production capacity within a reservoir. Integrating constraints from micro-pore network simulation and small-scale core displacement test data, while considering macro-heterogeneity near wellbore areas as flow unit divisions and superposition bases within large-scale reservoirs, it reveals the nonlinear flow characteristics of changes in liquid production capacity in water-flooding oil reservoirs based on microscopic digital core analysis. This approach aligns with findings from small-scale core testing and sweep coefficient correction while also addressing the non-uniform distribution characteristics of physical parameters within large-scale reservoirs.By integrating permeability field characteristics at three levels, this approach optimizes its technical advantages in describing dynamic permeability fields at each level, thereby facilitating precise prediction of water drive oil development effects.

Prediction of Oil–Water Two-Phase Flow Patterns Based on Bayesian Optimisation of the XGBoost Algorithm

With the continuous advancement of petroleum extraction technologies, the importance of horizontal and inclined wells in reservoir exploitation has been increasing. However, accurately predicting oil–water two-phase flow regimes is challenging due to the complexity of subsurface fluid flow patterns. This paper introduces a novel approach to address this challenge by employing extreme gradient boosting (XGBoost, version 2.1.0) optimised through Bayesian techniques (using the Bayesian-optimization library, version 1.4.3) to predict oil–water two-phase flow regimes. The integration of Bayesian optimisation aims to enhance the efficiency of parameter tuning and the precision of predictive models. The methodology commenced with experimental studies utilising a multiphase flow simulation apparatus to gather data across a spectrum of water cut rate, well inclination angles, and flow rates. Flow patterns were meticulously recorded via direct visual inspection, and these empirical datasets were subsequently used to train and validate both the conventional XGBoost model and its Bayesian-optimised counterpart. A total of 64 datasets were collected, with 48 sets used for training and 16 sets for testing, divided in a 3:1 ratio. The findings highlight a marked improvement in predictive accuracy for the Bayesian-optimised XGBoost model, achieving a testing accuracy of 93.8%, compared to 75% for the traditional XGBoost model. Precision, recall, and F1-score metrics also showed significant improvements: precision increased from 0.806 to 0.938, recall from 0.875 to 0.938, and F1-score from 0.873 to 0.938. The training accuracy further supported these results, with the Bayesian-optimised XGBoost (BO-XGBoost) model achieving an accuracy of 0.948 compared to 0.806 for the traditional XGBoost model. Comparative analyses demonstrate that Bayesian optimisation enhanced the predictive capabilities of the algorithm. Shapley additive explanations (SHAP) analysis revealed that well inclination angles, water cut rates, and daily flow rates were the most significant features contributing to the predictions. This study confirms the efficacy and superiority of the Bayesian-optimised XGBoost (BO-XGBoost) algorithm in predicting oil–water two-phase flow regimes, offering a robust and effective methodology for investigating complex subsurface fluid dynamics. The research outcomes are crucial in improving the accuracy of oil–water two-phase flow predictions and introducing innovative technical approaches within the domain of petroleum engineering. This work lays a foundational stone for the advancement and application of multiphase flow studies.

Analysis of Inter-Layer Interference in Multi-Layer Reservoir Commingled Production Wells

During the operation of commingled production wells, inter-layer interference is a key factor affecting the recovery rate and flooding extraction efficiency. This study proposes a well deliverability equation that is characterized by a multi-parameter coupled inter-layer interference coefficient, which is applied to quantify the commingled production wells in a multi-layer reservoir. This study used principal component analysis (PCA) to study the combined effects of correlation parameters for inter-layer interference. The results show that the starting pressure gradient and the crude oil viscosity contrast have the most significant impact on inter-layer interference. Changes in these two parameters directly enhance the heterogeneity between different oil layers, thereby intensifying inter-layer interference. Additionally, the positive correlation between permeability and permeability contrast also highlights the contribution of physical property differences in the oil layers to the interference. The sensitivity analysis shows the main influencing factors of inter-layer interference in commingled production wells. providing references for subsequent improvements and optimization of the exploitation schemes and adjustments in reservoir management measures. The results not only enhance the understanding of the mechanisms of inter-layer interference in the exploitation of multi-layer oil reservoirs but also provide scientific evidence and technical support for oilfield development.

Risk assessment of high maturity lacustrine shale oil reservoir based on pore-fracture connectivity and decane accessibility, Ordos Basin (China)

Risk assessment in the exploitation of lacustrine shale oil reservoir requires a more comprehensive approach. This task was accomplished through a wide range of complementary tests, including (ultra) small-angle neutron scattering (USANS/SANS), mercury intrusion capillary pressure (MICP), and scanning electron microscopy imaging after Wood's Metal (WM) impregnation. As a result, two key petrophysical parameters—pore-fracture connectivity and fluid accessibility—were determined. These parameters would help us to predict shale oil reservoir quality and significantly reduce the risks associated with exploitation. Results indicated that the Hg/WM only slightly fills the matrix pores due to elastic deformation under high pressure, particularly in clays and organic matter. The presence of pores in various sizes, determined by USANS/SANS and MICP made us to classify them into non-permeable, potentially permeable and permeable pores, among which permeable pores accounted for the highest proportion of the pores (58.98–79.03%). However, due to the restrictions of the throats, fractures (>10 μm) cannot effectively connect an important percentage of matrix pores, resulting in limited fluid flow. Moreover, the radius of gyration (Rg) obtained by contrast matching-SANS technique showed that oil molecules in the pore spaces of 2–110 nm are mainly in the adsorbed state. Collectively, such observations suggest that evaluating shale oil reservoirs, characterized by the above attributes, presents significant obstacles to efficient stimulation in production, making investment endeavors considerably challenging and risky.

Carbon Dioxide Oil Repulsion in the Sandstone Reservoirs of Lunnan Oilfield, Tarim Basin

The Lunnan oilfield, nestled within the Tarim Basin, represents a prototypical extra-low-permeability sandstone reservoir, distinguished by high-quality crude oil characterised by a low viscosity, density, and gel content. The effective exploitation of such reservoirs hinges on the implementation of carbon dioxide (CO2) flooding techniques. This study, focusing on the sandstone reservoirs of Lunnan, delves into the mechanisms of CO2-assisted oil displacement under diverse operational parameters: injection pressures, CO2 concentration levels, and variations in crude oil properties. It integrates analyses on the high-pressure, high-temperature behaviour of CO2, the dynamics of CO2 injection and expansion, prolonged core flood characteristics, and the governing principles of minimum miscible pressure transitions. The findings reveal a nuanced interplay between variables: CO2’s density and viscosity initially surge with escalating injection pressures before stabilising, whereas they experience a gradual decline with increasing temperature. Enhanced CO2 injection correlates with a heightened expansion coefficient, yet the density increment of degassed crude oil remains marginal. Notably, CO2 viscosity undergoes a substantial reduction under stratigraphic pressures. The sequential application of water alternating gas (WAG) followed by continuous CO2 flooding attains oil recovery efficiency surpassing 90%, emphasising the superiority of uninterrupted CO2 injection over processes lacking profiling. The presence of non-miscible hydrocarbon gases in segmented plug drives impedes the oil displacement efficiency, underscoring the importance of CO2 purity in the displacement medium. Furthermore, a marked trend emerges in crude oil recovery rates as the replacement pressure escalates, exhibiting an initial rapid enhancement succeeded by a gradual rise. Collectively, these insights offer a robust theoretical foundation endorsing the deployment of CO2 flooding strategies for enhancing oil recovery from sandstone reservoirs, thereby contributing valuable data to the advancement of enhanced oil recovery (EOR) technologies in challenging, low-permeability environments.

The Production Analysis and Exploitation Scheme Design of a Special Offshore Heavy Oil Reservoir—First Offshore Artificial Island with Thermal Recovery

More and more offshore heavy oil resources are discovered and exploited as the focus of the oil and gas industry shifts from land to sea. However, unlike onshore heavy oil reservoirs, offshore heavy oil reservoirs not only have active edge and bottom water but also have different exploitation methods. In this paper, a typical special heavy oil reservoir in China was analyzed in detail, based on geology–reservoir–engineering integration technology. Firstly, it is identified as a self-sealing bottom water heavy oil reservoir by analyzing its geological characteristics and hydrocarbon accumulation mechanism. Secondly, the water cut is initially controlled by oil viscosity, but subsequently, by reservoir thickness through the analysis of oil and water production data. Thirdly, the bottom oil–water contact of the reservoir was re-corrected to build an accurate 3D geological model, based on the production history matching of a single well and the whole reservoir. Lastly, a scheme of thermal production coupled with cold production was proposed to exploit this special reservoir, and the parameters of steam, N2, and CO2 injection and production were optimized to predict oil production. This work can provide a valuable development model for the efficient exploitation of similar offshore special heavy oil reservoirs.

Study on Foaming Agent Foam Composite Index (FCI) Correlation with High Temperature and High Pressure for Unconventional Oil and Gas Reservoirs

In the process of unconventional oil and gas reservoir exploitation, it is difficult to reduce drilling fluid lost in natural fractures, enhance the CO2 displacement effect and reduce foam drainage gas recovery costs. In most cases, foaming agents can solve these problems in a low-cost way in a short period of time. Foaming agent screening and evaluation is the key to this technology. However, there are few experimental tests used in the evaluation of foaming agent properties that match the actual unconventional oil or gas well conditions of high temperature and high pressure. Using the actual temperature and pressure conditions of a wellbore, the foaming capacity and half-life of two common foaming agents were systematically evaluated by using the high-temperature and high-pressure visual foam properties evaluation device (UPMX-500), in which the foaming agent’s volume concentration was 3‰ in a simulated formation water with a pH of 6 and salinity of 9 × 104 mg/L. The high-temperature (40 °C, 60 °C, 80 °C, 100 °C) and high-pressure (0.1 MPa, 6.0 MPa, 8.0 MPa, 10.0 MPa) effect on the foaming capacity and half-life was analyzed. Binary linear regression of pressure and temperature was carried out, taking the foam composite index as the target and using a formula with high correlation. The results showed that the foam composite index (FCI) of the two foaming agents was positively correlated with pressure and temperature. The correlation of UT-7 was FCI = 64.1196T + 735.713p − 2066.2, the correlation of HY-3K was FCI = 62.5523T + 7220.391p − 2415.6, and the coefficients of determination were 0.9799 and 0.9895, respectively, with an error of less than 10%. This correlation equation can provide a reference for accurately predicting the foaming capacity of foaming agents under high-temperature and high-pressure conditions and can also be used to optimize foaming agents or to qualitatively evaluate results for the efficient exploitation of unconventional oil and gas reservoirs.

Numerical study on gas production via a horizontal well from hydrate reservoirs with different slope angles in the South China Sea

AbstractIt is important to study the effect of hydrate production on the physical and mechanical properties of low‐permeability clayey–silty reservoirs for the large‐scale exploitation of hydrate reservoirs in the South China Sea. In this study, a multiphysical‐field coupling model, combined with actual exploration drilling data and the mechanical experimental data of hydrate cores in the laboratory, was established to investigate the physical and mechanical properties of low‐permeability reservoirs with different slope angles during 5‐year hydrate production by the depressurization method via a horizontal well. The result shows that the permeability of reservoirs severely affects gas production rate, and the maximum gas production amount of a 20‐m‐long horizontal well can reach 186.8 m3/day during the 5‐year hydrate production. Reservoirs with smaller slope angles show higher gas production rates. The depressurization propagation and hydrate dissociation mainly develop along the direction parallel to the slope. Besides, the mean effective stress of reservoirs is concentrated in the near‐wellbore area with the on‐going hydrate production, and gradually decreases with the increase of the slope angle. Different from the effective stress distribution law, the total reservoir settlement amount first decreases and then increases with the increase of the slope angle. The maximum settlement of reservoirs with a 0° slope angle is up to 3.4 m, and the displacement in the near‐wellbore area is as high as 2.2 m after 5 years of hydrate production. It is concluded that the pore pressure drop region of low‐permeability reservoirs in the South China Sea is limited, and various slope angles further lead to differences in effective stress and strain of reservoirs during hydrate production, resulting in severe uneven settlement of reservoirs.

Reporting nanoparticle tracers: Validation of performance in flow-through experiments simulating reservoir conditions

Characterization and monitoring of reservoir properties and conditions are key problems in the exploitation of subsurface aquifers and reservoirs, with tracer tests being an important tool that provides valuable insights into groundwater dynamics. The Reporting Nanoparticle Tracers (RNTs) approach was recently presented with the aim of expanding the scope of measureable parameters and the potential benefits of tracer tests in comparison to tests performed with traditional tracers. However, successful implementation of the concept depends on the ability of the nanoparticle tracers to exhibit a stable dispersion that facilitates sufficiently high recovery rates to allow for meaningful analysis. As a step forward toward the implementation of the approach, we used flow‑through studies with packed-bed quartz sand columns to compare the transport and retention properties of the RNTs with those of prevalent conservative molecular tracers and to show the feasibility of temperature detection. In the main experiments, the RNTs showed recovery rates around 80%, outperformed only by uranine (95 %) and surpassing eosin and sulforhodamine G (15 % and 50 % respectively). Thermally-activated RNTs could also be clearly differentiated from non-activated ones by a signal ratio difference of 50 %. These results validate the feasibility of application, especially considering the modularity of the nanoparticles, which enables adjustment of the RNTs to the hydrochemical conditions prevalent in the tested aquifer.

Synergizing shale enhanced oil recovery and carbon sequestration: A novel approach with dual lateral horizontal wells

The dual challenge of enhancing oil recovery while sequestering carbon dioxide (CO2) in oil reservoirs is a pivotal concern in the energy sector. CO2 injection is recognized for its ability to decrease oil density and viscosity, thereby improving oil mobility and recovery rates. Traditionally, efforts have been concentrated either on enhancing oil recovery (EOR) or carbon storage, but not many efforts spent to couple EOR and CO2 sequestration. Hence, novel techniques to optimize engineering designs to synergize EOR with CO2 sequestration is the best approach to maximize the opportunities of storing emission gas and contribute to the global world decarbonization goals.This study introduces an innovative dual lateral horizontal well design, aimed at simultaneously boosting oil recovery from shale reservoirs and enhancing CO2 retention. By integrating a conceptual understanding of oil recovery mechanisms with empirical data from the field, this research contrasts the proposed dual lateral design with the conventional Huff-n-Puff gas injection technique, commonly employed in shale oil formations.Our findings demonstrate that the dual lateral horizontal wells significantly outperform other injection methods in both oil recovery and CO2 storage. Upon optimization, the dual lateral injection design continues to surpass the Huff-n-Puff method in terms of CO2 storage, oil recovery, and net present value (NPV). This investigation not only presents innovative gas injection strategies in shale reservoirs but also provides insights into optimizing gas injection methods to enhance production efficiency and contribute to climate change mitigation through improved carbon capture and storage capacities.Through comprehensive numerical simulations and empirical data analysis, the study explores the optimization of well spacing, revealing that a dual lateral well with optimized spacing between 20 and 30 feet achieves the best outcomes in terms of oil recovery, CO2 retention, and net present value (NPV). The research presents a unique coupling of economic and environmental benefits, supported by economic analysis that includes the potential impact of CO2 tax credits.The novelty of this research is underscored by its integrated approach to CO2-EOR, the development of a dual lateral well design, and the optimization of well spacings for maximized efficiency. By providing a scalable solution that is both economically viable and environmentally sustainable, this research contributes a significant paradigm shift in the field of EOR and CO2 sequestration, with implications for policy and investment strategies in the energy sector. The findings propose a new direction for shale reservoir exploitation, promising to enhance production efficiency while contributing to global efforts in greenhouse gas reduction.

In-situ laboratory study on influencing factors of pre-SC-CO2 hybrid fracturing effect in shale oil reservoirs

Supercritical CO2 (SC-CO2) fracturing, being a waterless fracturing technology, has garnered increasing attention in the shale oil reservoir exploitation industry. Recently, a novel pre-SC-CO2 hybrid fracturing method has been proposed, which combines the advantages of SC-CO2 fracturing and hydraulic fracturing. However, the specific impacts of different pre–SC-CO2 injection conditions on the physical parameters, mechanical properties, and crack propagation behavior of shale reservoirs remain unclear. In this study, we utilize a newly developed “pre-SC-CO2 injection → water-based fracturing” integrated experimental device. Through experimentation under in-situ conditions, the impact of pre-SC-CO2 injection displacement and volume on the shale mineral composition, mechanical parameters, and fracture propagation behavior are investigated. The findings of the study demonstrate that the pre-injection SC-CO2 leads to a reduction in clay and carbonate mineral content, while increasing the quartz content. The correlation between quartz content and SC-CO2 injection volume is positive, while a negative correlation is observed with injection displacement. The elastic modulus and compressive strength exhibit a declining trend, while Poisson's ratio shows an increasing trend. The weakening of shale mechanics caused by pre-injection of SC-CO2 is positively correlated with the injection displacement and volume. Additionally, pre-injection of SC-CO2 enhances the plastic deformation behavior of shale, and its breakdown pressure is 16.6% lower than that of hydraulic fracturing. The breakdown pressure demonstrates a non-linear downward trend with the gradual increase of pre-SC-CO2 injection parameters. Unlike hydraulic fracturing, which typically generates primary fractures along the direction of the maximum principal stress, pre-SC-CO2 hybrid fracturing leads to a more complex fracture network. With increasing pre-SC-CO2 injection displacement, intersecting double Y-shaped complex fractures are formed along the vertical axis. On the other hand, increasing the injection rate generates secondary fractures along the direction of non-principal stress. The insights gained from this study are valuable for guiding the design of preSC-CO2 hybrid fracturing in shale oil reservoirs.

Effect of pore structure characteristics on gas-water seepage behaviour in deep carbonate gas reservoirs

The study of gas-water two-phase flow behavior has always been a focus and a difficult problem in the field of oil and gas seepage, and it is related to the formulation of reasonable development plans for oil and gas reservoirs. Deep carbonate gas reservoirs (depth>4500m) develop cross-scale porous media, which have extremely strong heterogeneity and very complex seepage characteristics. To the best of our knowledge, there has been no systematic study on the two-phase flow patterns of gas and water in deep carbonate gas reservoirs. This paper uses cast thin sections, scanning electron microscopy (SEM) and nuclear magnetic resonance (NMR) to study the influence of carbonate rock pore structure characteristics on gas storage and seepage capabilities. The results show that the existence of cavities enhances the gas storage capacity of the reservoir and improves the seepage capacity of pore-throat space near the cavity. Fractures can effectively communicate with isolated cavities, enhance reservoir connectivity, and thereby significantly improve the overall seepage capacity of the reservoir. The centrifugal technique was combined with NMR to study the movable fluid characteristics of carbonate reservoirs. The critical flow throat radius and movable fluid saturation of the reservoir reveal that the degree of development of cavities and fractures determines the mobility of the fluid in the reservoir. The fluid mobility in the fracture-cavity-type reservoir is the strongest, while the fluid mobility in the pore-type reservoir is the weakest. Analysis of the normalized curve of gas-water relative permeability under high temperature and pressure reveals that formation water preferentially enters connected pores with low seepage resistance, and the strong storage capacity of cavities can effectively delay the non-uniform intrusion of formation water. The results of water invasion simulation experiments show that the water invasion phenomenon can improve the gas production rate and recovery rate of pore-type reservoirs. However, the formation water flow and channeling phenomena caused by reservoir heterogeneity will cause a large amount of gas to be sealed in the pore space of cavity-type and fracture-cavity-type reservoirs, reducing the recovery rate and economic benefits of these reservoirs. These findings further provide solid fundamentals for efficient and effective exploitation of deep carbonate gas reservoirs.

Dynamics of Water Sighting and Injection Mechanisms in Fishbone Branch Wells in Bottom Water Reservoirs

Abstract Herringbone wells are effective in improving productivity for bottom water reservoirs; however, the main problem faced in the exploitation of bottom water reservoir is the ridge and cone of bottom water during the process of waterflooding, which leads to the decline of oil production. Therefore, predicting the breakthrough time and location of herringbone wells in bottom water reservoirs and then adjusting the water injection measures are of great significance for improving production and development. In this paper, we establish a three-dimensional coning model of bottom water to study the dynamic performance of bottom water rise, and the sequence of breakthrough position is determined by studying the breakthrough time along the wellbore. Based on the reservoir numerical simulation, we carry out a comprehensive adjustment of the water injection mechanism and develop a water injection scheme under the combination arrangement of vertical wells and herringbone wells. The results show that the bottom water breakthrough position of the branch well is mainly near the heel of the main branch or near the middle subsidence, and the recovery rate is the highest when the branch angle is 45 deg. The longer the shut-in time, the higher the recovery. The study is of great significance to optimize the layout and spatial structure, determine a reasonable working system, delay water channeling, and increase the cumulative production of herringbone wells.