Search Results (45)

The Triassic Chang 6 reservoir in the Suijing Oilfield is characterized by poor reservoir quality, pronounced heterogeneity, well-developed fractures, and suboptimal well pattern configuration, which collectively impede the establishment of an efficient displacement system. During the initial development phase, low production rates and delayed lateral response were observed, prompting a tight-spacing infill drilling pilot in the central low-productivity zone. However, conventional fracturing with upscaled stimulation volumes yielded limited fluid production uplift, rapid water cut escalation, and marginal incremental oil recovery. To address these challenges, a dual strategy integrating legacy fracture modification and new fracture generation was developed. Key fracturing parameters influencing reservoir drainage efficiency were systematically investigated, and an orthogonal experimental design was employed to optimize these parameters. The following conclusions were drawn: Stimulation timing should be postponed until water cut stabilizes below 20% in high-productivity zones; the optimal fracture half-length was determined to be 190 m; post-fracturing conductivity was optimized to 30 μm²·cm; and the turning angle for corner wells was set at 23°. For low-productivity zones with impaired reservoir properties that lead to retarded waterfront advancement, refracturing is recommended to be deferred until the water cut reaches 20–40%. The findings of this study provide a theoretical foundation for optimizing on-site refracturing processes and offer valuable guidance for addressing the optimization of fracturing parameters in low-permeability tight sandstone reservoirs. Full article

As oilfield development enters the mid-to-late stages, conventional water flooding techniques face increasing challenges such as high water cut and limited improvement in recovery efficiency. Gas flooding has gradually become a critical method for enhancing oil recovery (EOR). However, significant heterogeneity in pore structures within complex reservoirs severely affects flow capacity and development performance during gas flooding processes. To elucidate the microscale flow mechanisms influenced by heterogeneity, this study constructs a series of two-dimensional pore network models with varying degrees of heterogeneity based on an improved Quartet Structure Generation Set algorithm. Gas-oil two-phase flow simulations were conducted using the multiphase flow module of COMSOL Multiphysics® 6.2. By adjusting the bimodal pore size ratio and pore distribution parameters, the heterogeneity level of the reservoir was systematically controlled, and relative permeability curves were extracted to inform macro-scale development strategy design. Simulation results indicate that (1) strong heterogeneity reduces the stability of the displacement front, leading to pronounced gas channeling; (2) in strongly heterogeneous pore structures, residual oil saturation significantly increases, with small pore regions forming residual oil-enriched zones that are difficult to mobilize; (3) relative permeability curves vary markedly under different heterogeneity conditions—oil-phase permeability declines rapidly during displacement, while gas-phase permeability rises sharply at high gas saturation levels. This study systematically investigates, for the first time, the microscale impact of pore structure heterogeneity on gas flooding behavior and applies pore-scale simulation outcomes to optimize macro-scale development strategies. The findings offer theoretical support and a technical pathway for gas injection design in complex heterogeneous reservoirs. While two-dimensional pore-network models enable controlled mechanistic and sensitivity analyses of heterogeneity, they do not fully capture three-dimensional connectivity and tortuosity. Accordingly, our results are positioned as mechanistic priors that are calibrated to field data during upscaling. Full article

Enhanced oil recovery (EOR) techniques are essential for maximizing hydrocarbon extraction from mature reservoirs. CO₂ injection (CO₂-EOR) is a promising technology that improves oil recovery while contributing to greenhouse gas reduction. This study investigates the potential of miscible CO₂-enhanced oil recovery (CO₂-EOR) in the MakXX oilfield of southeastern Kazakhstan. The aim is to assess oil displacement efficiency and its impact on key rock properties, including porosity, permeability, and mineral composition, under reservoir conditions. Core flooding experiments were conducted at 13 MPa and 42 °C using high-precision equipment to replicate reservoir conditions. The core was analyzed before and after CO₂ injection using SEM, EDS, and XRD. The results revealed a 54% oil recovery efficiency, accompanied by a 19% decrease in permeability and 8% reduction in porosity due to mineral precipitation and clay transformation. These findings provide insight into the performance and limitations of CO₂-EOR and support its application in similar lithology. To confirm and upscale laboratory observations, numerical simulation was conducted using a compositional model. The results demonstrated improved oil recovery, pressure stabilization, and enhanced sweep efficiency under CO₂ injection, supporting the scalability and field applicability of the proposed EOR approach. Full article

Affected by discontinuities, the hydraulic properties of rock masses are characterized by significant scale dependency and anisotropy. Sampling a rock mass at any scale smaller than the representative elementary volume (REV) size may result in incorrect characterization and property upscaling. Here, a three-dimensional discrete fracture network (DFN) model was built using the joint data obtained from a dam site in southwest China. A total of 504 two-dimensional sub-models with sizes ranging from 1 m × 1 m to 42 m × 42 m were extracted from the DFN model and then used as geometric models for equivalent permeability tensor calculations. A series of steady-state seepage numerical simulations were conducted for these models using the finite element method. We propose a new method for estimating the REV size of fractured rock masses based on permeability. This method provides a reliable estimate of the REV size by analyzing the tensor characteristic of the directional permeability, as well as its constant characteristic beyond the REV size. We find that the hydraulic REV sizes in different directions vary from 6 to 36 m, with the maximum size aligning with the average orientation of joint sets and the minimum along the angle bisector of intersecting joints. Additionally, the REV size is negatively correlated with the average trace length of the two intersecting joint sets. We find that the geometric REV size, determined by the joint connectivity and density, falls into the range of the hydraulic REV size. The findings could provide guidance for determining the threshold values of numerical rock mass models. Full article

Hydrocarbon fields that contain non-associated gas, such as gas condensate, are highly valuable in terms of production. They yield significant amounts of condensate alongside the gas, but their unique behavior presents challenges. These reservoirs experience constant changes in composition and phases during production, which can lead to condensate blockage near wells. This blockage forms condensate bridges that hinder flow and potentially decrease gas production. To address these challenges, engineers rely on numerical simulation as a crucial tool to determine the most effective project management strategy for producing these reservoirs. In particular, relative permeability curves are used in these simulations to represent the physical phenomenon of interest. However, the representativeness of these curves in industry laboratory tests has limitations. To obtain more accurate inputs, simulations at the pore network level are performed. These simulations incorporate models that consider alterations in interfacial tension and flow velocity throughout the reservoir. The validation process involves reproducing a pore network flow simulation as close as possible to a commercial finite difference simulation. A scale-up methodology is then proposed, utilizing an optimization process to ensure fidelity to the original relative permeability curve at a microporous scale. This curve is obtained by simulating the condensation process in the reservoir phenomenologically, using a model that captures the dependence on velocity. To evaluate the effectiveness of the proposed methodology, three relative permeability curves are compared based on field-scale productivities and the evolution of condensate saturation near the wells. The results demonstrate that the methodology accurately captures the influence of condensation on well productivity compared to the relative permeability curve generated from laboratory tests, which assumes greater condensate mobility. This highlights the importance of incorporating more realistic inputs into numerical simulations to improve decision-making in project management strategies for reservoir development. Full article

The escalating environmental concerns associated with conventional plastic packaging have accelerated the development of sustainable alternatives, making food packaging a focus area for innovation. Bioplastics, particularly polyhydroxyalkanoates (PHAs), have emerged as potential candidates due to their biobased origin, biodegradability, and biocompatibility. PHAs stand out for their good mechanical and medium gas permeability properties, making them promising materials for food packaging applications. In parallel, zinc oxide (ZnO) nanoparticles (NPs) have gained attention for their antimicrobial properties and ability to enhance the mechanical and barrier properties of (bio)polymers. This review aims to provide a comprehensive introduction to the research on PHA/ZnO nanocomposites. It starts with the importance and current challenges of food packaging, followed by a discussion on the opportunities of bioplastics and PHAs. Next, the synthesis, properties, and application areas of ZnO NPs are discussed to introduce their potential use in (bio)plastic food packaging. Early research on PHA/ZnO nanocomposites has focused on solvent-assisted production methods, whereas novel technologies can offer additional possibilities with regard to industrial upscaling, safer or cheaper processing, or more specific incorporation of ZnO NPs in the matrix or on the surface of PHA films or fibers. Here, the use of solvent casting, melt processing, electrospinning, centrifugal fiber spinning, miniemulsion encapsulation, and ultrasonic spray coating to produce PHA/ZnO nanocomposites is explained. Finally, an overview is given of the reported effects of ZnO NP incorporation on thermal, mechanical, gas barrier, UV barrier, and antimicrobial properties in ZnO nanocomposites based on poly(3-hydroxybutyrate), poly(3-hydroxybutyrate-co-3-hydroxyvalerate), and poly(3-hydroxybutyrate-co-3-hydroxyhexanoate). We conclude that the functionality of PHA materials can be improved by optimizing the ZnO incorporation process and the complex interplay between intrinsic ZnO NP properties, dispersion quality, matrix–filler interactions, and crystallinity. Further research regarding the antimicrobial efficiency and potential migration of ZnO NPs in food (simulants) and the End-of-Life will determine the market potential of PHA/ZnO nanocomposites as active packaging material. Full article

Deep and ultra-deep reservoirs are characterized by low porosity and permeability, pronounced heterogeneity, and complex pore structures, complicating permeability evaluations. Permeability, directly influencing the fluid production capacity of reservoirs, is a key parameter in comprehensive reservoir assessments. In the X Depression, low-porosity and low-permeability formations present highly discrete and variable core data points for porosity and permeability, rendering single-variable regression models ineffective. Consequently, accurately representing permeability in heterogeneous reservoirs proves challenging. In the following study, lithological and physical property data are integrated with mercury injection data to analyze pore structure types. The formation flow zone index (FZI) is utilized to differentiate reservoir types, and permeability is calculated based on core porosity–permeability relationships from logging data for each flow unit. Subsequently, the average permeability for each flow unit is computed according to reservoir classification, followed by a weighted average according to effective thickness. This approach transforms logging permeability into drill stem test permeability. Unlike traditional point-by-point averaging methods, this approach incorporates reservoir thickness and heterogeneity, making it more suitable for complex reservoir environments and resulting in more reasonable conversion outcomes. Full article

This study examines the connections between various fracture indicators and production data with an example from one of the giant fields in the Middle East producing complex fractured carbonate lithologies. The field under study hosts two reservoirs with a long development and production history, including carbonates from the Asmari and Bangestan Formations. A fracture intensity map was generated based on the interpretation of image logs from 28 wells drilled within the field. Mud loss data were collected and mapped based on the geostatistical Gaussian Random Function Simulation (GRFS) algorithm. Maximum curvature maps were generated based on Asmari structural surface maps. Comparing the results shows a good agreement between the curvature map, fault distribution model, mud loss map, fracture intensity map, and productivity index. The results of image log interpretations led to the identification of four classes of open fractures, including major open fractures, medium open fractures, minor open fractures, and hairline fractures. Using the azimuth and dip data of the four fracture sets mentioned above, the fracture intensity log was generated as a continuous log for each well with available image log data. For this purpose, the fracture intensity log and a continuous fracture network (CFN) model were generated. The continuous fracture network model was used to generate a 3D discrete fracture network (DFN) for the Asmari Formation. Finally, a 3D upscaled model of fracture dip and azimuth, fracture porosity, fracture permeability, fracture length, fracture aperture, and the sigma parameter (the connectivity index between matrix and fracture) were obtained. The results of this study can illuminate the modeling of intricate reservoirs and the associated production challenges, providing insights not only during the initial production phase but also in the application of advanced oil recovery methods, such as thermal recovery. Full article

Soil moisture plays a crucial role in various hydrological processes and energy partitioning of the global surface. The Soil Moisture Active Passive-Sentinel (SMAP-Sentinel) remote-sensing technology has demonstrated great potential for monitoring soil moisture with a maximum spatial resolution of 1 km. This capability can be applied to improve the weather forecast accuracy, enhance water management for agriculture, and managing climate-related disasters. Despite the techniques being increasingly used worldwide, their accuracy still requires field validation in specific regions like Thailand. In this paper, we report on the extensive in situ monitoring of soil moisture (from surface up to 1 m depth) at 10 stations across Thailand, spanning the years 2021 to 2023. The aim was to validate the SMAP surface-soil moisture (SSM) Level 2 product over a period of two years. Using a one-month averaging approach, the study revealed linear relationships between the two measurement types, with the coefficient of determination (R-squared) varying from 0.13 to 0.58. Notably, areas with more uniform land use and topography such as croplands tended to have a better coefficient of determination. We also conducted detailed soil core characterization, including soil–water retention curves, permeability, porosity, and other physical properties. The basic soil properties were used for estimating the correlation constants between SMAP and in situ soil moistures using multiple linear regression. The results produced R-squared values between 0.933 and 0.847. An upscaling approach to SMAP was proposed that showed promising results when a 3-month average of all measurements in cropland was used together. The finding also suggests that the SMAP-Sentinel remote-sensing technology exhibits significant potential for soil-moisture monitoring in certain applications. Further validation efforts and research, particularly in terms of root-zone depths and area-based assessments, especially in the agricultural sector, can greatly improve the technology’s effectiveness and usefulness in the region. Full article

Gas flooding and foam flooding are potential technologies for tertiary oil recovery in fractured-vuggy reservoirs. The development and mechanism research of fractured-vuggy reservoirs is difficult due to the complex structures and the strong heterogeneity of fractured-vuggy reservoirs. Visualization simulation is one of the effective methods to study the flow behavior of fluid in fractured-vuggy reservoirs. In this study, an upscaling method of visualization simulation from one dimension (1D) to three dimensions (3D) was established, and the physical models of fractured-vuggy reservoirs were designed and fabricated. Water flooding, gas flooding, and gel foam flooding were carried out in the models. The experimental results showed that gas flooding has a single flow channel and water flooding has multiple flow channels in fractures and vugs. Gel foam with an excellent capability of mobility control and a high microscopic displacement efficiency swept in all directions at a uniform velocity. The EOR mechanisms of gel foam in fractured-vuggy reservoirs were mainly as follows: reducing interfacial tension, increasing mobility ratio, selectively plugging high permeability channels, and discontinuous flow. In the displacement process of fractured-vuggy reservoirs, water should be injected from the well at the bottom of the reservoir, and gas should be injected from the well located in the vug at the high part of the reservoir. Gel foam with strong stability and high viscosity should be selected and injected in most kinds of injection wells in fractured-vuggy reservoirs. This study provides a complete method of visualization simulation for the study of flow behavior in fractured-vuggy reservoirs and provides theoretical support for the application of gas flooding and gel foam flooding in fractured-vuggy reservoirs. Full article

Transport and retention of multi-sized suspended granules are common phenomena in fracture media of oil, gas and geothermal reservoirs. It can lead to severe permeability damage and productivity decline, which has a significant impact on the efficient development of underground resources. However, the granule transport and retention behaviors remain not well understood and quantified. The novel stochastic model is proposed for the multi-sized suspended granule transport in naturally fractured reservoirs accounting for granule retention and fracture clogging kinetics. A percolation fracture network is proposed considering fracture connectivity evolution during suspended granule transport. Granule retention and fracture clogging dynamics equations are proposed to account for incomplete fracture clogging by retained granules. The microscale stochastic model is allowed for upscaling to predict the multi-sized granule transport behavior in naturally fractured reservoirs. The model solution exhibits preferential plugging of fractures with sizes equal to or below the granule size. Multi-sized suspended granule shows great advantages over mono-sized suspended granule in the control of permeability damage induced by granule retention and fracture clogging. The retained granule concentration and permeability damage rate decrease with fracture network connectivity improvement. The experimental investigation on size-exclusion suspended granule flow has been performed. The model-based prediction of the retained granule concentration and permeability variation history shows good agreement with the experimental data, which verifies the developed model. Full article

Carbon dioxide (CO₂) dissolution is the secondary trapping mechanism enhancing the long-term security of CO₂ in confined geological formations. CO₂ injected into a randomly multilayered formation will preferentially migrate along high permeability layers, increasing CO₂ dissolution efficiency. In this study, sequential Gaussian simulation is adopted to construct the stratified saline formations, and two-phase flow based on MRST is established to illustrate the spatial mobility and distribution of CO₂ migration. The results show that gravity index $G$ and permeability heterogeneity ${\sigma }_Y^2$ are the two predominant factors controlling the spatial mobility and distribution of CO₂ transports. The CO₂ migration shows a totally different spatial mobility under different gravity index and heterogeneity. When the permeability discrepancy is relatively larger, CO₂ preferentially migrates along the horizontal layer without accompanying the vertical migration. For the formation controlled by gravity index, CO₂ migration is governed by supercritical gaseous characteristics. For the medium gravity index, the upward and lateral flow characteristics of the CO₂ plume is determined by gravity index and heterogeneity. When the gravity index is smaller, permeability heterogeneity is the key factor influencing CO₂ plume characteristics. Permeability heterogeneity is the decisive factor in determining final CO₂ dissolution efficiency. This investigation of CO₂ mobility in randomly multilayered reservoirs provides an effective reference for CO₂ storage. Full article

Carbonate reservoirs are a highly heterogeneous type of reservoir characterized by the presence of a large amount of vugs and pores. During two-phase displacement, the two-phase flow regime in the vugs might be gravity segregated. The distribution pattern of two-phase fluid in the vugs would accelerate the water flow in downward and horizontal directions, meanwhile decelerating in an upward direction, resulting in a different oil recovery ratio. This gives rise to the question of whether the relative permeability should be modeled as a directional dependent in a vugular porous medium since it is usually treated as an isotropic quantity. In this study, via both experiment and numerical simulation, we demonstrate that the relative permeability of vugular porous medium is dependent on the angle between the flow direction and the horizontal plane and should be considered for oil recovery estimation for carbonate reservoirs. Using the transmissibility-weighted upscaling method and a single-vug model, the relative permeability curves for different flow directions are obtained by numerical simulation. A directional relative permeability model for a vugular porous medium is also proposed. Full article

As a key technical aspect contributing to shale gas development, nanoconfined methane flow behavior has received tremendous research interest, which remains challenging to understand clearly. The majority of previous contributions put emphasis on the mechanism model for methane confined in a single nanopore; at the same time, the other part focusing on an upscaling approach fails to capture the spatial pore-network characteristics as well as the way to assign pressure conditions to methane flow behavior. In light of the current knowledge gap, pore-network modeling is performed, in which a pore coordination number, indicating the maximum pores a specified pore can connect, gas flow regimes classified by Knudsen numbers, as well as different assigned pressure conditions, are incorporated. Notably, the pore-network modeling is completely self-coded, which is more flexible in adjusting the spatial features of a constructed pore network than a traditional one. In this paper, the nanoconfined methane flow behavior is elaborated first, then the pore network modeling method based on the mass conservation principle is introduced for upscaling, and in-depth analysis is implemented after that. Results show that (a) as for porous media with pore sizes ranging from 5~80 nm, dramatic advancement on apparent gas permeability takes place while pressure is less than 1 MPa; (b) apparent gas permeability evaluated at a specified pressure shall be underestimated by as much as 31.1% on average compared with that under the pressure-difference condition; (c) both a large pore size and a high coordination number are beneficial for strong gas flow capacity through nanoscale porous media, and the rising ratio can reach about 6 times by altering the coordination number from 3 to 7, which is quantified and presented for the first time. Full article