Reservoir Heterogeneity Research Articles

A hybrid numerical model for coupled hydro-mechanical analysis during CO2 injection into heterogeneous unconventional reservoirs

This paper presents a hybrid numerical model for simulating compressible multiphase multicomponent transport in deformable, heterogeneous unconventional reservoirs. A fully implicit theoretical framework for coupled hydromechanical behaviour is established, in which the flash calculation is avoided. To preserve the local mass conversation, an element based finite volume method is used to spatially discretize mass conversation equations. Linear momentum equilibrium equation is discretized with finite element method. Two numerical approaches are coupled through sharing the same shape functions. An implicit mid-interval backwards difference algorithm is used to handle the temporal derivative. Reliability and efficiency of the developed model have been examined by verification tests against available analytical or numerical solutions. The coupled hydromechanical processes in heterogeneous reservoirs were simulated. The results of numerical experiments show that oscillatory problem for saturation in heterogeneous media can be eliminated, demonstrating better performance of developed model for heterogeneous reservoir simulations. Reservoir performance is significantly shaped by its heterogeneity through controlling fluid flow and time for CO2–CH4 displacement. Simulation results show that the time required for completion of CO2–CH4 displacement increases by about 250 days when considering heterogeneity effect. In conclusion, this study offers a valuable tool for facilitating the development of CO2-enhanced unconventional gas recovery.

A composite water saturation model of continental mixed shale oil reservoirs based on complex lithology identification

The complex lithology, frequent interbedding and strong heterogeneity of the shale oil reservoir in Lucaogou Formation of the Middle Permian in Jimsar Sag lead to the complexity of litho‐electric parameters and the low accuracy of conventional reservoir saturation evaluation methods. Therefore, in this paper, automatic lithologic identification was firstly performed with the optimization inversion method of mineral components and K‐means clustering algorithm, and then, litho‐electric experiments were carried out to determine the litho‐electric parameters of different lithologies. Furthermore, the shale oil reservoir saturation calculation models of different lithologies were optimized and determined. Then, a composite water saturation model (Composite‐SW) based on complex lithology identification was constructed. Finally, the model was verified and analysed with the experimental results of water saturation. The coefficient of correlation between the calculation results of the Composite‐SW model and the core experiment results reached .88, indicating that the model was much better than conventional models. The model can be widely applied in logging evaluation of the continental mixed shale oil reservoir in the study area. The study provides a new idea for oil saturation evaluation of continental shale oil reservoirs and is significant for evaluating other types of shale oil reservoirs.

Reservoir properties of effusive rocks of the Muradkhanli field (Azerbaijan)

The presence of oil accumulations in igneous rocks has been known for quite a long time. Geologists estimate that oil reserves in eruptive and weathered metamorphic rocks reach 1 % of the world’s proven oil reserves. At the Shaimskoye field (Western Siberia), oil is found in the weathered granites of the basement. Oil has been found in eruptive rocks in Texas (USA) fields, the most famous of which is the Litton Springs field. Oil is found in metamorphosed shales in the western part of the Los Angeles basin, the porosity of which is caused by the development of cracks in the roof of crystalline shales. Petroleum is extracted from serpentinites in Cuba. Basic igneous rocks contain petroleum at the Ferbro field in Mexico.At the Khukhrinsky gas field, which islocated at the north-western end of the Dnieper-Donets depression, the crystalline basement rocks are oil and gas bearing, from which commercial hydrocarbon inflows have been obtained. In the White Tiger field (Bach Ho), located on the southern shelf of Vietnam, commercial oil accumulations are also found in crystalline basement rocks.
 At the Muradkhanli field in Azerbaijan, the industrial accumulation of petroleum belongs to the igneous rocks of the Upper Cretaceous age. The natural oil and gas reservoir of the Muradkhanli field is confined to the erosion zone of the upper part of the section of these rocks.
 This work aims to determine the reservoir properties of the rocks of the Muradkhanli deposit, which belong to igneous rocks, in different ways.
 The method of estimation of final oil recovery of complex structure reservoirs was proposed for useful capacity and oil recovery of homogeneous media; different variants of the volumetric method were used for reservoirs with complex structures of pore space filling a complex and heterogeneous natural reservoir; values of hydrocarbon reserves of increased and secondary capacity were calculated for the study interval; distributions of oil reserves with right-sided asymmetry, where Mo<Me<X, were presented; it was determined that in effusive cores oil saturation and fluid filtration are caused by tectonic fracturing and cavernousness.
 Permeability varies in a wide range: 0.73·10–15—1.31·10–15 m2; the largest specific fraction of crack density is in the range 0—0.1 cm/cm2, the average value is 0.29 cm/cm2, with crack depth they decrease from 0.9 to 0.1 cm/cm2.
 The studies have shown that the natural reservoir of oil and gas in the Muradhanli field is associated with the erosion zone of the upper part of the igneous rock section.

Deep Dive into the factors influencing acoustic velocity in the Dalan-Kangan formations, the central Persian Gulf

The propagation of acoustic waves in rocks is directly influenced by the rocks’ elastic properties. To evaluate petrophysical properties from acoustic data, it is essential to understand the factors that influence the variations in acoustic velocity of sedimentary rocks. Carbonate reservoirs are heterogeneous, and their evaluation is complicated. A closer look at the factors affecting the elastic properties of these rocks is essential because they reveal important information about the reservoir properties and their formation evaluation. Rock physics modeling relies on laboratory-measured acoustic data. This study, however, employs acoustic logs to elucidate the key factors influencing sonic velocity, offering a more comprehensive and field-applicable perspective. Samples were prepared from the Permian–Triassic Upper Dalan and Kangan formations. Porosity, permeability, sedimentary textures, mineralogy, and pore types were investigated. Furthermore, compressional, shear, and Stoneley well-logs data were recorded and converted to acoustic velocity in the sampled interval. Porosity-velocity modeling based on the differential effective medium (DEM) theory was performed for different values of equivalent pore aspect ratio (EPAR). The results show that there is a strong inverse relationship between acoustic velocities and porosity. Acoustic velocities also exhibit an inverse correlation with permeability, but the strength of these relationships is relatively weak. Acoustic velocities are not affected by carbonate textures. A specific texture may exhibit different velocities due to the influence of diagenetic processes. Mineralogy has only a minor influence on acoustic velocities. Dolostones have a slightly higher velocity than limestones, but the difference is insignificant. Stoneley log values are slightly different in limestone and dolostone, because this wave propagates along the mud-borehole interface. The velocities were affected by the variations in pore types within the studied formations. Therefore, in carbonate rocks, porosity, and the pore types play a significant role in controlling acoustic velocities. The value of EPAR = 0.15 can be considered as the boundary between stiff pores (moldic and vuggy) and soft pores (interparticle, intercrystalline, micro-intercrystalline, and microporosity). The lower EPAR value of interparticle pores in limestones compared to dolostones can be attributed to diagenetic processes such as dolomitization and compaction. The findings of this study can help to better understand what factors affect acoustic velocity in carbonate rocks. This study also shows that acoustic logs data can be effectively used in rock physics modeling and pore type identification. By identifying the pore types, it is possible to recognize diagenetic processes and determine the rock types to control the heterogeneity and estimate reservoir quality.

Modelling the coupled heterogeneities of the lacustrine microbialite-bearing carbonate reservoir of the Yacoraite Formation (Salta, Argentina)

The Yacoraite Formation is a complex lacustrine microbialite-bearing carbonate formation whose heterogeneity is due to different sedimentary facies associations and several microbialite geobodies. The bi-variate plurigaussian geostatistical method is applied to simulate in parallel these two types of heterogeneity in a 3D reservoir-scale geological model. Each variable is simulated by a complete plurigaussian method based on geological interpretation and field observations and quantifications. They are coupled through the occurrence of the microbialites within the sedimentary facies and associated into combined facies giving a one-glance representation of the reservoir heterogeneity, then used to constrain the porosity simulation.

Efficient optimization of fracturing parameters with consideration of fracture propagation and heterogeneity in tight gas reservoirs

The parameters of fractures, such as fracture geometries, placement, and conductivity, are critical for the production of horizontal wells in tight gas reservoirs. Current studies on fracture parameter optimization, especially those using the optimization algorithms, are often based on the assumptions that the fractures are uniformly placed with equal length and conductivity. However, non-uniform designs of fracture spacing have been proved to be effective in reducing fracture interference as well as increasing the well production, especially with strong rock heterogeneity. In addition, most of the current literature focuses on identifying optimal hydraulic fracture geometries without considering the fracture propagation process, which may oversimplify the evaluation of completion cost and result in fracture geometries that cannot be realized in practice.In this paper, an automatic optimization process, which could efficiently couple the fracture propagation, is proposed to optimize the fracture parameters. The genetic algorithm (GA) with penalty function method is used to optimize the constraint and non-linear problem. A modified PKN fracture propagation model is established to quickly predict the hydraulic fracture geometries. Fracture locations and fluid injection volume are sequentially optimized with consideration of heterogeneous rock properties. Model parameters are taken from typical tight gas horizontal wells in Jinqiu gas field in Sichuan Province, China. The results show the importance of permeability on both fracture length and production in tight gas well. The lower the permeability, the more significant the production increase after fracture location optimization. More fractures tend to be placed in area with small permeability and fewer fractures are required in highly permeable regions. With an increase in rock heterogeneity, the distribution of fractures becomes more uneven. Conversely, increasing the number of fractures can lead to a more even distribution of fractures. More fluid should be injected in low-permeability regions according to the optimization results. The optimization method is applied to a practical tight gas well in Sichuan Basin and the cumulative gas production can be increased by 6.5% to 8% when compared with the initial uniform designs.

Numerical upscaling of anisotropic failure criteria in heterogeneous reservoirs

With advances in characterizing the reservoir heterogeneities and modeling the complex reservoir-geomechanical behavior using modern geological modeling software and simulators, the impact of geological uncertainties on reservoir-geomechanical responses has drawn increasing attention for an improved engineering design and decision makings in subsurface developments. Robust and efficient upscaling techniques for heterogeneous reservoirs have emerged as the key to enable field-scale reservoir-geomechanical assessments while consider the impact of lithological heterogeneities like weak bedding planes. The proposed upscaling technique is based on local continuum geomechanical simulations with user-defined boundary conditions on each upscaled region, thus, it can reproduce the anisotropic stress-dependent failure criteria caused by sub-grid scale heterogeneities. This upscaling technique is applied in a reservoir-geomechanical simulation of a steam-assisted gravity drainage (SAGD) project and reduces the computational time by 94%. The complex thermal-hydro-mechanical (THM) interactions in SAGD, including temperature, pressure, saturation fields, surface heave, and plastic strain, are well reproduced by the upscaled model. The minimum factor of safety (FOS) of the caprock for potential shear failure in a field-scale SAGD case study with multilayer caprocks is also reasonably matched by the upscaled model. The improved computational efficiency and reasonable accuracy of the upscaled model can be a useful tool to investigate the impact of injection pressures on production performance and caprock integrity for decision making of SAGD. Moreover, this method addresses the enduring problem of finding anisotropic failure criteria for heterogeneous reservoirs, bridging the gap between computational efficiency and the desire to consider detailed geological features in geomechanical modeling of larger domains. The improved computational efficiency and reasonable accuracy of upscaled models enable reliability analysis and uncertainty quantification for geomechanical analyses that require numerous realizations with complex geology.

Dynamic Variation of Full-Scale Pore Compressibility and Heterogeneity in Deep Shale Gas Reservoirs: Implications for Pore System Preservation

Dynamic Variation of Full-Scale Pore Compressibility and Heterogeneity in Deep Shale Gas Reservoirs: Implications for Pore System Preservation

Micro and Macro Flooding Mechanism and Law of a Gel Particle System in Strong Heterogeneous Reservoirs.

To address the issue of ineffective injection resulting from the consistent channeling of injected water through highly permeable channels in ultra-deep, high-temperature, high-salinity, and strongly heterogeneous reservoirs during the production process, a gel particle profile control agent suitable for high-temperature and high-salinity conditions was chosen. With the help of the glass etching visual microscopic model and the heterogeneous long core model, the formation mechanism of a water flooding channeling path and the distribution law of the remaining oil were explored, the microscopic profile control mechanism of the different parameters was clarified, and the profile control effect of macroscopic core displacement was analyzed. The research shows that the formation mechanism of a water flooding channeling path is dominated by the distribution law of the permeability section and the connection mode between different penetration zones. The remaining oil types after water flooding are mainly contiguous block, parallel throats, and multi-branch clusters. The profile control effect of gel particles on reservoir vertical heterogeneity is better than that of reservoir lateral heterogeneity. It was found that 10 wt% submicron particles with a median diameter of 600 nm play a good role in profiling and plugging pores of 5-20 μm. In addition, 10 wt% micron-sized particles with a median diameter of 2.63 μm mainly play a strong plugging role in the pores of 20-30 μm, and 5 wt% micron-sized particles with a median diameter of 2.63 μm mainly form a weak plugging effect on the pores of 10-20 μm. The overall profile control effect of 10 wt% submicro particles is the best, and changes in concentration parameters have a more significant effect on the profile control effect. In the macroscopic core profile control, enhanced oil recovery (EOR) can reach 16%, and the gel particles show plugging, deformation migration, and re-plugging. The research results provide theoretical guidance for tapping the potential of the remaining oil in strong heterogeneous reservoirs. To date, the gel particles have been applied in the Tahe oilfield and have produced an obvious profile control effect; the oil production has risen to the highest value of 26.4 t/d, and the comprehensive water content has fallen to the lowest percentage of 32.1%.

Microfluidic devices, materials, and recent progress for petroleum applications: A review

AbstractMicrofluidic devices are miniaturized systems that manipulate fluids on a small scale, typically at microlitre or nanolitre volumes. They have received significant attention in various industries, including petroleum applications. The recent advancements in microfluidic devices for petroleum applications have the potential to improve oil recovery efficiency, reduce costs, and provide valuable insights into fluid behaviour and reservoir characterization. This paper aims to provide a comprehensive overview of microfluidic devices, their materials, and their applications in the petroleum industry. The first section of the paper focuses on describing the materials used in microfluidic devices specifically tailored for energy sector applications. In the second section, the paper highlights relevant applications and discoveries in petroleum research, showcasing the innovative techniques and special features enabled by microfluidic devices. These applications include but are not limited to asphaltenes characterization, enhanced oil recovery (EOR), and water treatment. The versatility and customization of microfluidic devices have allowed researchers to accurately represent fractures, ensure chemical conformance, simulate high pressure–high temperature conditions and reservoir heterogeneity, and study geochemical interaction. Additionally, molecular tagging and machine learning techniques have been employed for image analysis, further enhancing the capabilities of microfluidic devices. Throughout the paper, the advantages and disadvantages of implementing microfluidic devices and utilizing specific materials are thoroughly discussed. This analysis provides valuable insights into the challenges and potential limitations associated with this technology. To conclude, the paper offers suggestions, ideas, and highlights for future research paths, pointing toward promising directions for further exploration in this field.

Assessment of World’s First Two Polymer Injectivity Tests Performed in Two Giant High-Temperature/High-Salinity Carbonate Reservoirs Using Single-Well Simulation Models and Pressure Falloff Tests Analysis

Summary Polymer flooding is a mature enhanced oil recovery (EOR) technology that has been widely implemented around the world for more than 60 years. Polymer flooding mostly targets medium- to high-permeability sandstone reservoirs with moderate salinity, hardness, and temperatures. However, in the last few years, the envelope of polymer flooding has been expanded to harsher reservoir conditions of high-temperature and high-salinity mixed-wet to oil-wet heterogeneous carbonate reservoirs. Development of novel polymers and innovative field application concepts has allowed for the reconsideration of polymer-based EOR as a promising technology to improve sweep efficiency for these challenging reservoirs. Polymer injectivity is one of the key challenges for polymer flooding projects and requires a rigorous derisking program that includes laboratory and field testing. A comprehensive laboratory program was designed to assess and investigate polymer thermal stability, polymer rheology in porous media, adsorption, and injectivity using reservoir core samples. In addition, two polymer injectivity tests (PITs) were performed in two giant light oil (0.3 cp) carbonate reservoirs in onshore Abu Dhabi under harsh conditions of high salinity (>200 g/L), high divalent ions (>20 g/L), high temperature (>250°F), and H2S concentration of up to 40 ppm. The polymer used during the two PITs (PIT 1 2019 and PIT 2 2021) is a new generation of EOR polymer (SAV 10) with high 2-acrylamido-tertiary-butyl sulfonic acid content that was specifically developed to tolerate such harsh conditions. This paper is focused on the interpretation of the PITs and lessons learned for future polymer-based EOR projects. The detailed data acquired in both tests were used to evaluate the polymer injectivity at representative field conditions and in-depth mobility reduction. The PITs together with the extensive laboratory studies are part of a thorough derisking program for the upcoming world’s first innovative hybrid EOR multiwell pilots—simultaneous injection of miscible gas and polymer (SIMGAP) and simultaneous injection of water and polymer (SIWAP). Both PITs are composed of three stages that include a multirate waterflood baseline, polymer injection using different rates, and polymer concentrations followed by extended chase waterflooding. In addition, a sequence of multiple pressure falloff (PFO) tests was acquired during the PIT executions and analyzed to obtain the required uncertainty parameters for the history-matching exercise. Polymer preshearing was considered as part of both PIT programs with the aim to homogenize the polymer molecular weight distribution and reduce possible shear-thickening effects near the wellbore as per laboratory measurements. Two single-well 3D simulation models were built to incorporate the information from polymer laboratory studies and to interpret the large field data sets acquired during the PITs. Lessons learned from PIT 1 allowed us to optimize the PIT 2 design program and achieve better understanding of polymer characteristics. The interpretation of the pressure transient analysis (PTA) of the PFO tests and the 3D simulation models of the two PITs confirmed the generation of polymer banks and demonstrated effective propagation of the polymer into the reservoirs at target concentrations and representative rates of the future SIWAP and SIMGAP interwell pilots.

Research on EOR for ultralow interfacial tension foam in high-temperature and high-salinity reservoirs: flooding simulation and application in Shengli Oilfield

For high temperature and high salinity reservoirs, the foam formulation system is required to have better foaming capacity and foam stability under formation conditions in tertiary EOR. In order to obtain a new foam agent suitable for this type of oil reservoir, through the compounding and testing of 7 common oilfield foam chemical agents, 15 formulated foam agents are tested and screened. Then the foam displacement experiment of the dual sand packs model was established to simulate the new foam flooding process. The production dynamic of the high-permeability sand pack and the low-permeability sand pack was captured and analyzed, and EOR mechanism of the foam system in the heterogeneous reservoir was clarified. The experimental results show that the formulation of B4(anionic & nonionic combined surfactant) & FSN100(fluorinated surfactant) with a mass proportion of 2:3 (BF23) has the best performance in terms of foaming properties, low interfacial tension reduction, and oil washing efficiency. Furthermore, BF23 foam injection greatly increased the recovery factor from 36.7% to 61.6%, clearly displacing the remaining oil in the low-permeability pack. Finally, the new foam agent solution used in Shenger block of Shengli Oilfield shows its good value for enhanced oil recovery.

Using distributed acoustic sensing to characterize unconventional reservoirs via perforation-shot triggered P waves

The lack of knowledge of lateral heterogeneity in unconventional reservoirs commonly has negative impacts on drilling, completion efficiency, and production. However, current methods, such as well logging and seismic surveying, are limited in their ability to characterize unconventional reservoirs. We develop an alternative geophysical approach that uses distributed acoustic sensing (DAS) and perforation shots to characterize unconventional reservoirs. In our field data set, DAS-recorded perforation shots show strong P-wave signals. The recorded P-wave waveforms from the study area exhibit dispersive behavior, which can be clearly identified after signal processing. The spatial variations in phase velocity along the horizontal wellbore can be reliably measured by averaging the measurements from multiple closely situated perforation shots. We observe a low phase-velocity zone along the study well, which is spatially consistent with the well logs and root mean square amplitude extracted from the 3D seismic volume. The observed dispersive behavior of P waves is validated through numerical modeling. By comparing the results from the proposed method with those from modeling results and other measurements, we conclude that the proposed method results in a reasonable radius of investigation for unconventional reservoir characterization. The method also has the potential to infer hydraulic fracturing effectiveness by comparing the phase-velocity difference before and after stimulation. The data acquisition of the proposed workflow can be combined with perforation shot operations, which provides a cost-effective and suitable approach to investigating lateral heterogeneity in unconventional reservoirs.

Clarifying the contribution of multiscale pores to physical properties of Chang 7 tight sandstones: insight from full-scale pore structure and fractal characteristics

The pore structure and its heterogeneity of tight reservoirs are key factors affecting the storage and percolation of crude oil. The pore system of Chang 7 tight sandstone has multi-scale and multi-type characteristics. However, the contribution of different pore types and pore sizes to the physical properties of Chang 7 tight sandstone is still unclear. In this paper, we collected a suite of Chang 7 tight sandstones to investigate the full-scale pore structure and fractal characteristics by casting thin section, field emission scanning electron microscope, two-dimensional multi-scale backscattered scanning electron microscopy, N2 adsorption (NA) and NMR. The pore diameters of Chang 7 tight sandstone are usually distributed between 0.001 and 20 μm. Intercrystalline pores are mainly distuibuted <500 nm. Dissolution pores vary from 100 nm to 100 μm. Residual intergranular pores range from 1 μm to 40 μm. Based on the fractal characteristics, pore system is divided into macropores (mainly >300 nm), mesopores (mainly 7–300 nm), and micropores (mainly <7 nm). Micropores are adsorb-fluid pores that do not contribute to the storage and percolation but contribute significantly to contrasting specific surface area. Mesopores represent bound-fluid pores and only contribute to total porosity but not to permeability. Macropores represent movable-fluid pores, contributing to both porosity and permeability. The content and heterogeneity of macropores control the quality of Chang 7 tight sandstone. When macropore volume is >12×10−3 mL/g, the continuous percolation network consists entirely of macropores, resulting in higher porosity and permeability of the reservoir. Moreover, reservoir physical properties show excellent correlation with macropore heterogeneity. These results demonstrate that the content and heterogeneity of macropores are key indicators indicating the quality of the Chang 7 tight sandstones.

Performance of multistage-fractured horizontal wells with secondary discrete fractures in heterogeneous tight reservoirs

AbstractA significant portion of tight sandstone reservoirs commonly displays intricate fluvial channels or fault systems. Despite various attempts at analytical/semi-analytical modeling of multistage-fractured horizontal wells (MFHWs) in unconventional reservoirs, the majority of studies have focused on scenarios with homogeneous original physical properties, neglecting cases where MFHWs traverse multiple regions in channelized heterogeneous reservoirs. Comprehending the influence of heterogeneous and leaky faults on the performance of MFHWs is essential for efficient development. This study presents an innovative semi-analytical model to analyze the pressure transient behavior of MFHWs with secondary fractures as they traverse multiple regions in banded channel heterogeneous reservoirs, particularly considering the presence of partially-communicating faults. The approach combines the source method and Green’s function method to obtain solutions, introducing a novel technique for discretizing fractures without discretizing interfaces. The effects of the reservoir heterogeneity, partially-communicating faults and fractures system on pressure behavior are analyzed. The results indicate that the pressure behavior of MFHWs passing through regions with different physical properties exhibits distinctive characteristics, differing from both the homogeneous case and the heterogeneous cases where the well does not traverse distinct regions. Permeability heterogeneity influences the curves of all other flow regimes, except the early and late flow regimes. Faults affect transient pressure behavior only when not positioned in the middle of each two primary fractures. Region area heterogeneity primarily influences the medium flow regimes. This work provides valuable insights into the performance of MFHWs in channelized heterogeneous reservoirs, offering technical support for well testing in these reservoirs.

Radiation-Induced Polymerization of Thermo-Responsive Polymers for Enhanced Sweep Efficiency in Heterogeneous Oil Reservoirs

Radiation-Induced Polymerization of Thermo-Responsive Polymers for Enhanced Sweep Efficiency in Heterogeneous Oil Reservoirs

Rate Transient Analysis of Heterogeneous Unconventional Reservoirs Exhibiting Deteriorated Induced-Fractures with Exponential Permeability Profile.

Deterioration of induced fractures is common in hydraulically fractured tight or shale reservoirs due to the energy dissipation of the fracturing operation. New models that account for stimulated reservoir heterogeneity are needed for the rate transient analysis of unconventional formations. In this study, we present a practical and straightforward solution for heterogeneous fractured reservoirs by introducing the concept of dynamic average permeability (DAP). An explicit equation of average permeability for linear flow in heterogeneous formation is derived by integrating the solution of the linear flow diffusivity equation and exponential permeability profile function into the Darcy flow model. Methodologies for performance forecast and evaluation of the distance of investigation (DOI) for heterogeneous unconventional reservoirs are proposed based on the DAP concept. Early deviation from the straight line of reciprocal-of-production-rate versus square-root-of-time plot occurs in highly heterogeneous reservoirs, in contrast to the departure caused by the boundary-domination effect. Meanwhile, the study results show that the DOI is significantly reduced in severely permeability-deteriorated unconventional formations. The accuracy and applicability of the new solution have been validated through real examples and synthetic numerical simulations. The analytical solution for transient linear flow in heterogeneous formation with an exponential permeability profile in the Laplace domain is also provided for the verification of the DAP method. The method proposed in this work can be readily applied to rate transient analysis and production forecasting of heterogeneous unconventional reservoirs, avoiding the complex Laplace solution and numerical inversion process.

Mechanism of plugging high permeability core and decreasing reservoir heterogeneity with ultra-dry CO2-in-water foam

For oil recovery in low-permeability oil fields, ultra-dry CO2 foam flooding possesses the dual advantages of pure CO2 flooding and surfactant flooding, and is also effective for CO2 storage. Herein, ultra-dry CO2-in-water (C/W) foam with 10 v/v% water content was used for core plugging and to decrease the heterogeneity of oil reservoirs. The resistance coefficient (Rf) and residual resistance coefficient (Rff) characterizing the foam-plugged cores were measured at different foam existence times (different times after forming the foam) and for cores with different permeabilities. As the foam existence time increased, the non-uniformity of the foam intensified, resulting in a decrease in its ability to plug cores. Specifically, the resistance coefficient (Rf) decreased from 12.179 to 6.802, while the residual resistance coefficient (Rff) decreased from 7.149 to 3.809. With a decrease in the core permeability, Rf decreased from 26.525 to 10.398, Rff decreased from 17.313 to 4.230, and the ability of the foam to plug cores decreased, indicating that the ultra-dry C/W foam could effectively plug the high-permeability layer and decreasing the reservoir heterogeneity. Based on the distribution of foam and pore size, three plugging mechanisms were proposed: single-bubble bridge, multi-bubble accumulation and foam compression, deformation and rupture. Additionally, a scale factor I (I = Rff/Rf) was introduced to evaluate the stability of the residual foam in the plugged core. After different existence times, the value of I for the foam injected into the core was stable at 0.55–0.6, indicating good stability of the foam. Finally, oil recovery in parallel cores was evaluated and two-phase flow was simulated based on the phase-field method, which further proved that the ultra-dry C/W foam can effectively decrease the reservoir heterogeneity and enhance oil recovery in the low-permeability zone.

Evaluation of Profile Control and Oil Displacement Effect of Starch Gel and Nano-MoS2 Combination System in High-Temperature Heterogeneous Reservoir.

The Henan Oilfield's medium-permeability blocks face challenges such as high temperatures and severe heterogeneity, making conventional flooding systems less effective. The starch gel system is an efficient approach for deep profile control in high-temperature reservoirs, while the nano-MoS2 system is a promising enhanced oil recovery (EOR) technology for high-temperature low-permeability reservoirs. Combining these two may achieve the dual effects of profile control and oil displacement, significantly enhancing oil recovery in high-temperature heterogeneous reservoirs. The basic performance evaluation of the combination system was carried out under reservoir temperature. Displacement experiments were conducted in target blocks under different permeabilities and extreme disparity core flooding to evaluate the combination system's oil displacement effect. Additionally, the displacement effects and mechanisms of the starch gel and nano-MoS2 combination system in heterogeneous reservoirs were evaluated by simulating interlayer and intralayer heterogeneity models. The results show that the single nano-MoS2 system's efficiency decreases with increased core permeability, and its effectiveness is limited in triple and quintuple disparity parallel experiments. After injecting the starch gel-nano-MoS2 combination system, the enhanced oil recovery effect was significant. The interlayer and intralayer heterogeneous models demonstrated that the primary water flooding mainly affected the high-permeability layers, while the starch gel effectively blocked the dominant channels, forcing the nano-MoS2 oil displacement system towards unswept areas. This coordination significantly enhanced oil displacement, with the combination system improving recovery by 15.33 and 12.20 percentage points, respectively. This research indicates that the starch gel and nano-MoS2 combination flooding technique holds promise for enhancing oil recovery in high-temperature heterogeneous reservoirs of Henan Oilfield, providing foundational support for field applications.

Spatial Distribution of Heterogeneity of the AB Reservoir Unit of Zubair Formation in the South Rumaila Oilfield, Southern Iraq

Reservoir heterogeneity, a critical factor in fluid flow and recovery processes, manifests at various scales and is influenced by depositional facies, diagenesis, and structural features. This study aims to quantify and map the spatial heterogeneity within Unit AB of Zubair Formation, south Rumaila oilfield, utilizing the Lorenz coefficient (Lk ) for vertical heterogeneity and ordinary kriging for spatial interpolation. Analyzing porosity and permeability data from 44 boreholes using the Lk coefficient revealed that the AB reservoir unit is primarily homogeneous, with 65% of boreholes exhibiting homogeneity. However, heterogeneity is present in the central and southeastern portions of the oilfield. Without considering the reservoir’s heterogeneity, placing injection wells along the eastern flank could lead to increased water production and reduced volumetric sweep efficiency.