Reservoir Heterogeneity Research Articles

Comparison of the Petrophysical and Reservoir Heterogeneity of the Mauddud Formation in Halfaya and Ratawi Oil Fields, Southern Iraq

Comparison of the Petrophysical and Reservoir Heterogeneity of the Mauddud Formation in Halfaya and Ratawi Oil Fields, Southern Iraq

Comprehensive Investigation of Factors Affecting Acid Fracture Propagation with Natural Fracture

Acid fracturing is a crucial stimulation technique to enhance hydrocarbon recovery in carbonate reservoirs. However, the interaction between acid fractures and natural fractures remains complex due to the combined effects of mechanical, chemical, and fluid flow processes. This study extends a previously developed hydro-mechano-reactive flow coupled model to analyze these interactions, focusing on the influence of acid dissolution. The model incorporates reservoir heterogeneity and simulates various scenarios, including different stress differences, approaching angles, injection rates, and acid concentrations. Numerical simulations reveal distinct propagation modes for acid and hydraulic fractures, highlighting the significant influence of acid dissolution on fracture behavior. Results show that hydraulic fractures are more likely to cross natural fractures, whereas acid fractures tend to be arrested due to wormhole formation. Increasing stress differences and approaching angles promote fracture crossing, while lower angles favor diversion into natural fractures. Higher injection rates facilitate fracture crossing by increasing pressure accumulation, but excessive acid concentrations hinder fracture initiation due to enhanced wormhole formation. The study demonstrates the importance of tailoring fracturing treatments to specific reservoir conditions, optimizing parameters to enhance fracture propagation and reservoir stimulation. These findings contribute to a deeper understanding of fracture mechanics in heterogeneous reservoirs and offer practical implications for improving the efficiency of hydraulic fracturing operations in unconventional reservoirs.

Quantitative characterization of porosity evolution in the Triassic Chang 8 tight sandstone reservoir during hydrocarbon accumulation in the Maling area, Ordos Basin, China

The Maling area in the Ordos Basin is characterized by delta front deposits. The principal oil-bearing layer, Chang 8 Member (the 8th member of the Triassic Yanchang Formation), manifests low-to-ultra-low porosity and permeability due to the interplay of depositional, diagenetic, and burial processes. The reservoir exhibits pronounced heterogeneity and diagenetic alterations, which limit the efficacy of hydrocarbon exploration. Methodologies employed for this research encompass grain size imaging, physical property assays, petrographic thin sections, scanning electron microscopy, high-pressure mercury intrusion, and X-ray diffraction. These techniques facilitated a comprehensive investigation into the diagenetic attributes and compaction mechanisms of the reservoir. A porosity evolution simulation equation tailored to the Chang 8 tight sandstone reservoir was formulated based on diagenetic evolution traits and geological influences. Interdependencies and correlations among various diagenetic processes were analyzed. During diagenesis, compaction, cementation, and replacement led to a reduction in primary porosity, whereas dissolution-induced secondary pores served as high-permeability channels. A quantitative model for porosity evolution was developed alongside qualitative assessments, achieving a deviation of 3.18% when compared to gas porosity measurements. Evaluation of four representative samples revealed that compaction-induced diagenetic alteration predominates, with burial depth, formation age, and cement types playing critical roles in the evolution of reservoir porosity. This differential diagenetic evolution elucidates the underlying causes of variability in reservoir properties and heterogeneity in pore structure, providing valuable insights for future exploration strategies.

A Novel Quantitative Water Channeling Identification Method of Offshore Oil Reservoirs

Offshore oilfields are characterized by loose sandstone reservoirs, strong heterogeneity and high injection and production intensity. Water channeling gradually develops after entering the high water cut stage, which weakens production performance. Current identification methods usually have high computational costs and low efficiency. A quantitative identification model of water channeling based on inter-well connection units has been established by simplifying the complex reservoir system into a connection network between injectors and producers, which can quickly and accurately obtain strength characteristic parameters for waterflow channels. In addition, a comprehensive evaluation factor M and classification standard for water channeling suitable for offshore heterogeneous reservoirs have been proposed. It indicates a thief zone when M is larger than 0.65, a predominant waterflow channel when M is between 0.55 and 0.65, and no water channeling when M is smaller than 0.55. The application of (an) offshore S oilfield demonstrates that the new method successfully identifies 18 segments of the thief zone and 19 segments of the predominant waterflow channel and improves computational speed by 100 times compared with the conventional numerical modeling method. This novel method allows for rapid and accurate identification and prediction of water channeling, including location, directions, and strengths, thereby providing timely and practical guidance for inefficient water channel treatment.

A coupled displacement-pressure model for elastic waves induce fluid flow in mature sandstone reservoirs

Elastic (seismic) wave stimulation is considered one of the unconventional enhanced oil recovery (EOR) methods. Increasing water quantity in the high permeability layer of a mature oil reservoir is highly challenging and can significantly decrease the ultimate recovery due to the reservoir heterogeneity. Using seismic waves can be considered low-cost, environmentally friendly, and illuminates the entire reservoir size compared to conventional EOR methods. A numerical model is developed by extending the Quintal approach for seismic attenuation due to wave-induced fluid flow (WIFF) to incorporate capillary pressure in partially saturated porous media and shift undrained boundary conditions to exclude external flow stress for drained boundary conditions. Therefore, the fluid distribution due to the capillary effect makes the developed finite element method (FEM) u-p model more widely applicable for oil recovery in mature reservoirs. A two-layer partially saturated media was subjected to compressive seismic stress at low frequency (3 Hz). The results indicated that the vertical displacement gradients of the bottom and upper layers decline with excitation time for both fully and partially saturated media. On the other hand, partially saturated pore pressure gradients of both the upper and bottom layers have higher amplitudes with excitation time than fully saturated pore pressure gradients due to the influence of capillar pressure. The cumulative crossflow oil volume for 180 days of continuous stimulation was 1176 bbl, 1032 bbl, and 648 bbl in low permeability layers: 200 md, 100 md, and 50 md, respectively. Therefore, the developed model has the potential for field-scale EOR applications. The study also suggests coupling elastic EOR with CO2 flooding to recover more oil due to increasing fluid mobility and relative permeability to oil in low-permeability reservoirs or tight formations.

Simultaneous quantification of triple pore types in carbonate reservoirs using well logs and seismic data

Accurate characterization of carbonate pore types is of great significance for seismic reservoir characterization. However, the existing pore-type inversion methods cannot characterize the coexistence of three main pore types (vuggy pores, matrix pores, and cracks) for each modeling point because they apply a simple iterative procedure without using S-wave velocity. To overcome this problem, we develop a simultaneous triple pore-type inversion (TPTI) strategy to estimate the porosities of different pore types from the P- and S-wave velocities using a global optimization technique known as very fast simulated annealing. Considering the rock composition variation and pore geometry complexity, we first establish an easy-to-implement multipore effective medium model for carbonate reservoirs based on the Keys-Xu model and Gassmann’s equation. Then, the applicability of this model is verified by two sets of experimental acoustic measurements for synthetic and actual carbonate samples. A good comparison of model predictions with laboratory data indicates that our model can effectively capture the elastic responses of carbonate rocks with different pore shapes, which provides a theoretical basis for quantifying multiple pore types. Based on the developed model, we further develop a TPTI method. We apply it to describe pore-type distribution from well logs and seismic data in a heterogeneous carbonate reservoir from the Sichuan Basin in southwest China. Real applications suggest that our method significantly improves the accuracy of porosity estimates for different pore types, outperforming the traditional dual pore-type inversion method. This advancement holds considerable promise for the seismic characterization of pore types in ultradeep carbonate reservoirs.

Experimental Evaluation of Blockage Resistance and Position Caused by Microparticle Migration in Water Injection Wells

Offshore oil field loose sandstone reservoirs have high permeability. However, during the water injection process, water injection blockage occurs, causing an increase in injection pressure, making it impossible to continue injecting water on site. Current research mainly focuses on the factors causing water injection blockage, with less attention given to the blockage locations and the pressure increase caused by water injection. There is a lack of research on the change in the law of injection capacity. This paper establishes a simulation experiment for water injection blockage that can accommodate both homogeneous and heterogeneous cores. The experimental core is 1 m long and capable of simulating the blockage conditions in the near-well zone during water injection, thereby analyzing the core blockage position and blockage pressure. The study clarifies the influence of water quality indicators, heterogeneity, and core length on the blockage patterns in reservoirs during water injection. The research findings are as follows: I. The reservoir blockage samples were characterized using scanning electron microscopy (SEM), casting thin sections, and X-ray diffraction (XRD) analysis. The results indicate that the main factors causing blockage are clay, silt, and fine particulate suspensions, with the fine particles mainly consisting of hydrated silicates and alkali metal oxides. The primary cause of blockage in loose sandstone is identified as the mechanism of migration and accumulation of clay, fine rock particles, and suspended matter in the injected water. II. By monitoring pressure and permeability changes in the core flooding experiments, the impact of reservoir heterogeneity on water injection capacity was evaluated. The evaluation results show that the blockage locations and lengths in heterogeneous cores are twice those in homogeneous cores. III. For heterogeneous reservoirs, if the initial permeability at the inlet is lower than in other segments of the core, significant blockage resistance occurs, with the final resistance being 1.27 times that of homogeneous cores. If the initial permeability at the inlet is higher than in other parts, the final blockage resistance is close to that of homogeneous cores. This study provides theoretical support for the analysis of blockage locations and pressures in loose sandstone water injection and offers technical support for the design of unplugging ranges and pressures after blockage in heterogeneous formations. At the same time, it provides a theoretical basis for selecting the direction of acidizing after blockage occurs in loose sandstone.

Perforation design coupled with heterogeneity during underground hydrogen storage in steeply dipping anticline aquifers

Hydrogen has been recognized as a crucial energy carrier to reduce greenhouse gas emissions. However, as it is not always possible to meet current energy demands, underground hydrogen storage (UHS) is required for energy supply and consumption. UHS is an emerging field of study with limited investigations regarding structural conditions and wellbore perforation design in steeply dipping anticline aquifers. This study investigates different perforation schemes with respect to UHS within steeply dipping anticline aquifers to find the most suitable injection/production design while examining small-scale reservoir heterogeneities. Several UHS improvement techniques are evaluated, including water and CO2 injection through flank wells during hydrogen production. The results indicate that the highest hydrogen production is achieved with a fully perforated H2 well located at the crest as it provides the maximum contact between the hydrogen and aquifer layers during H2 injection/production. In contrast, hydrogen production is diminished with increased heterogeneity, as higher heterogeneities raise the chance of H2 being trapped. To enhance UHS performance, first H2 initialization before UHS beginning was evaluated but the results showed that it does not enhance UHS performance in a steeply dipped anticline aquifers, as effectively as it does in gas reservoirs. Water injection from flank wells during H2 production cycles showed improvement in hydrogen withdrawal, while water production experienced a slight increase. CO2 injection from flank wells was evaluated to effectively increase H2 recovery as a cushion gas and to maintain hydrogen purity during production. According to results, hydrogen purity was not affected only in high heterogeneity, since more hydrogen gets trapped in the small-scale high heterogeneity level, which prevents the mixing zone from reaching the H2 well during production. While the method prevents hydrogen contamination in anticline aquifers due to the high dip angle coupled with high heterogeneity levels, it leads to a lower hydrogen recovery.

Microfacies impacts on reservoir heterogeneity of early cretaceous Yamama carbonate reservoir in South Iraq

Detailed well-log interpretations, including gamma-ray, density, neutron, and resistivity, alongside petrographic analysis of 100 samples over 170 m of drill cores, have revealed factors influencing reservoir heterogeneity in the Yamama Formation, Ah’Dimah Oilfield, southern Iraq. The formation comprises four reservoir units (YA-YD) separated by four non-reservoir units (BA-BD). The reservoir units are subdivided into subunits. YB2, YB3, and YC demonstrate the best reservoir quality, while YD2 is water-bearing. Seven microfacies were identified within both reservoir and non-reservoir units, deposited in a shallow carbonate ramp. These include bioclastic wackestone, Lithocodium-Bacinella float/boundstone, peloidal cortoid intraclast grainstone, reefal bioclastic rudstone, bioclastic foraminiferal wacke/packstone, miliolidal pack/grainstone, and spiculitic foraminiferal wackestone. Despite the deep burial depth of the formation (> 4000 m), it maintained good porosity values in most intervals, reaching up to 20%. Early isopachous cement protected porosity and dissolution enhanced porosity, while cementation, compaction, and pyritization reduced it. The reservoir units correlate with depositional environments, being deposited in the shoal area, while non-reservoir units were deposited in lagoon, middle, and outer-ramp settings. The Lithocodium-Bacinella float/boundstone and reefal bioclastic rudstone facies, forming reefal patches and build-ups within the shoal, dominated in YB2 and YC. Targeting these patches northeast of Ah’Dimah Oilfield is promising for field development.

Faulted karst reservoir spaces in Middle-Lower Triassic carbonates, Qingjiang Region, Yangtze block, China

The complexity and heterogeneity of ultra-deep faulted karst reservoirs pose significant challenges for hydrocarbon exploration. In this study, we integrated remote sensing image analysis, field measurements, and core sample testing to evaluate the characteristics and controlling factors of carbonate reservoir spaces within the Middle and Lower Triassic formations along a regional strike-slip fault in the Qingjiang region of China. The strike-slip fault zone is composed of multiple fault cores and damage zones. Based on differences in damage zone width and linear fault density, the fault zone was subdivided into transtensional and transpressional segmentations. The carbonate reservoirs, primarily developed within the damage zones, consist of fractures, fracture clusters, and cavities. Detailed measurements of the carbonate outcrops were conducted to obtain geometric parameters of the reservoir spaces. Quantitative results indicate that in the transtensional segmentation, the reservoir is dominated by tensile fracture-cavity systems, characterized by larger fracture apertures (0.13–1.25 m), higher linear fracture density (0.38–8.37 m⁻1), and well-developed cavities (0.03–4.84 m2), which contribute to better fluid connectivity and storage capacity. In contrast, the transpressional segmentation is dominated by compressional fracture-fracture cluster systems, with longer fractures (0.11–12.52 m), smaller fracture apertures (0.01–0.94 m), and extensive fracture clusters development (0.18–17.87 m2), but with lower fluid connectivity and limited storage capacity. Mechanical testing results show that the average compressive strength in the transtensional segmentation (133.95 MPa) is significantly higher than that in the transpressional segmentation (70.28 MPa). In terms of mineral composition, the transtensional segmentation has a higher calcite content, whereas the transpressional segmentation is richer in dolomite and quartz. Based on the observed differences in reservoir space characteristics across the strike-slip fault zone, we discussed the combined effects of structural segmentation, formation thickness, rock mechanics, and brittle mineral content on reservoir space development. The study emphasizes that stress conditions (primary factor) and material properties (secondary factor) jointly control fluid migration and storage efficiency in the reservoirs. Additionally, we suggest that the outcrop studies in the Qingjiang region provide valuable geological analogs for faulted karst reservoirs, offering critical insights for improving the precision of carbonate reservoir exploration and optimizing production efficiency.

A prediction method of oil recovery for hot water chemical flooding in heavy oil reservoirs: Semi-analytical stream tube model

Abstract Chemical agents (polymer and surfactant) assisted hot water flooding is an effective means of enhancing oil recovery in heterogeneous and heavy oil reservoirs. The rapid prediction of oil recovery through hot water chemical flooding is very important. The stream tube model is a fast analytical method for predicting water flooding recovery, but it is not suitable for hot water chemical flooding. In this paper, a permeability distribution model for multi-stream tubes is established based on permeability variation coefficient using normal distribution function for reservoir heterogeneity, Using GOMPERTZ growth function model to characterize the changes in stream tube temperature, polymer viscosity, and surfactant concentration with injection volume, Using Brooks-Corey model to describe the influence of interfacial tension and temperature on the relative permeability curve. Finally, an analytical stream tube model for hot water chemical flooding of heavy oil reservoirs was established. The time discrete method is used to solve the model, then the graphs of the relationship between oil recovery and water cut are obtained. Compared with numerical simulation methods, the prediction error of oil recovery is less than 2%, and the calculation time is reduced by 89%. This model has been successfully applied to X oilfield. Based on historical fitting, it is predicted that hot water chemical flooding can enhance oil recovery by 6.3% compared to water flooding. This paper provides a fast calculation method for predicting and evaluating the effectiveness of hot water chemical flooding in heavy oil reservoirs.

Unconventional Fracture Networks Simulation and Shale Gas Production Prediction by Integration of Petrophysics, Geomechanics and Fracture Characterization

The proficient application of multistage fracturing methods enhances the status of the Duvernay shale formation as a highly esteemed shale reservoir on a global scale. Nevertheless, the challenge is in accurately characterizing unconventional fracture behavior and predicting shale productivity due to the complex distributions of natural fractures, pre-existing faults, and reservoir heterogeneity. The present study puts forth a Geo-Engineering approach to comprehensively investigate the Duvernay shale reservoir in the vicinity of Crooked Lake. To begin with, on the basis of the experimental results and well-logging interpretations, a high-quality petrophysical and geomechanical model is constructed. Subsequently, the establishment of an unconventional fracture model (UFM) takes into account the heterogeneity of the reservoir and the interactions between hydraulic fractures and pre-existing natural fractures/faults and is further validated by 18,040 microseismic events. Finally, the analysis of well productivity is conducted by numerical simulations, revealing that the agreement between the simulated and observed production magnitudes exceeds 89%. This paper will guide the efficient development of increasingly important unconventional shale resources.

Exploring comparative heterogeneity management for precise water saturation assessment in carbonate formations: Dean-Stark measurements and beyond

Accurate determination of water saturation is a critical aspect of reservoir characterization and development potential of a hydrocarbon field. The inherent heterogeneity in carbonate reservoirs significantly influences the Archie equation coefficients and, consequently, water saturation calculations. In this study, 160 direct core sample water saturation measurements using the Dean-Stark method have been used. The primary goal was to identify the most suitable reservoir heterogeneity management approach for water saturation calculation. The research focuses on the Dalan and Kangan formations (equivalent to Khuff Formation), known as some of the most hydrocarbon-rich (gas) reservoirs globally, located in the western part of the Persian Gulf. To manage reservoir heterogeneity, we employed various techniques, including Winland R35, flow zone indicator, Lucia, pore types, and electrofacies, utilizing porosity and permeability core data, thin section studies, and well-logging data to classify the studied intervals into more homogeneous categories. Subsequently, we measured Archie parameters and, for the first time, water saturations derived from Dean-Stark measurements were compared with Archie saturations from various heterogeneity management methods. Additionally, the influence of geological and petrophysical parameters on the accuracy of water saturation calculations in different rock types is discussed. Our results highlighted the significance of geometrical attributes of pore types, pore throat radius, and permeability as key factors affecting the precision of water saturation calculations. Moreover, our investigation revealed that Lucia's rock typing methodology exerted a substantial influence on the control of permeability and the distribution of water saturation within the reservoir. Our analysis revealed that the electrofacies method provided the most precise estimates for water saturation, with a mean difference of 0.07 (v/v) units compared to the Dean-Stark method. Subsequently, the accuracy of predicted water saturation in rock types determined by the Lucia method, with a mean error of 0.09 (v/v), ranked second among the rock typing methods. Winland R35 and flow zone indicator methods exhibited the highest uncertainty in water saturation estimation, with mean differences of 0.23 and 0.21 (v/v), respectively, compared to the Dean-Stark method.

Multi-scale model for evaluating stress fluctuation in shale gas reservoirs considering geomechanical heterogeneity

In this article, a numerical model considering multi-scale flow and heterogeneity of shale reservoirs is developed to analyze the spatiotemporal evolution of the stress field in shale gas production. After considering the geomechanical heterogeneity, the variation in the local rock mechanical parameters of the reservoir, and the increase in the effective stress of the reservoir will cause local stress fluctuations. In the hydraulic fracture control area, the average stress fluctuation coefficient is higher, indicating a stronger “stress heterogeneity.” When the homogeneity increases from 5 to 100, the fluctuation range of the minimum horizontal principal stress increases by 28.89 MPa, and the fluctuation range of the principal stress difference increases by 7.35 MPa. The presence of natural fractures can significantly impact the coupled hydraulic-mechanical processes of the reservoir, increasing the number of high-speed permeation channels penetrating the system. The greater the density and permeability, the smaller the minimum horizontal principal stress and the larger the principal stress difference. The angle of natural fractures directly influences the direction of stress drop, with an average minimum horizontal principal stress occurring when the angle of natural fractures is at 60°/120°.

Unlocking thin sand potential: a data-driven approach to reservoir characterization and pore pressure mapping

The gradual decline of production of the major fields of the Indus Basin has influenced the field pressure. Therefore, the prospects need to be assessed by the petro-elastic relationship. This study highlights the value-addition for identifying gas pockets within the E-Sand of the Lower Goru Formation through estimating and populating petro-elastic properties. A probabilistic neural network (PNN) was employed to develop the relationship of pore pressure to the inverted properties. The outcomes will help identify the high-pressure areas in accordance with the petro-elastic relationship for optimizing production strategy. In order to evaluate the petro-elastic relationship, stochastic seismic inversion was employed to holistically capture the reservoir’s variability. Pore pressure volumetric was estimated from inverted attributes using a PNN, a non-linear algorithm that was more suited to heterogeneous reservoirs. The main objective of the research is achieved via enhanced resolution of elastic properties attained through the integration of stochastic inversion and PNN processes. The high-resolution elastic properties including P-impedance, S-impedance, and Vp/Vs ratio can delineate the heterogeneities more profoundly. The petrophysical volumes obtained via enhanced inverted properties combined with pore-pressure through PNN illuminated the potential facies and the correlations in predicting the properties. The procedure provides a linkage of elastic, petrophysical, and geomechanical properties that is helpful for professionals covering a broad field of the petroleum sector. The developed workflow can be followed globally where problems occur regarding heterogeneities and early depletion.

In situ combustion performance in heavy oil carbonate reservoirs: A triple-porosity numerical model

This study aims to address the challenges of oil recovery in highly heterogeneous carbonate reservoirs by employing a novel triple-porosity numerical model approach for in-situ combustion (ISC). The primary focus is on the performance of ISC within isolated vuggy pore spaces, a characteristic feature of such reservoirs. By simulating triple-porosity through artificially induced vuggs, core matrix, and fractures, we evaluated the feasibility of the ISC technique for heavy oil recovery in a dolomite reservoir using a combustion tube setup.The numerical model, calibrated through history matching, incorporates an extended kinetic reaction scheme to better represent high-temperature oxidation processes. Experimental and simulation results show a strong correlation in temperature profiles, ignition timing, and fluid production, effectively reproducing the observed gas compositions. This integrated experimental and numerical approach demonstrates the potential for applying ISC in triple-porosity systems, offering valuable insights for field-scale implementations in similarly complex carbonate reservoirs. The novelty of this research lies in its comprehensive modeling of the first ISC experiment in a triple-porosity framework, providing a deeper understanding of the interactions between matrix, fracture, and vugg networks, and paving the way for enhanced oil recovery (EOR) strategies in challenging reservoir environments.

Study on multi-cluster fracture interlaced competition propagation model of hydraulic fracturing in heterogeneous reservoir

The heterogeneity of the reservoir plays a crucial role in influencing the propagation of multi-cluster hydraulic fractures in horizontal wells. To explore this impact, a seepage-stress-damage coupled model was developed in this study for analyzing the competitive propagation of multi-cluster fractures utilizing the finite-discrete element method. Utilizing the model, a random assignment program has been developed to establish the coupling distribution of mechanical parameters between matrix elements and discrete elements for characterizing the reservoir heterogeneity. Simultaneously, a wellbore flow model describing the pressure drop of fracturing fluid flow is developed by introducing pipe flow element and fluid connection element, enabling the realization of dynamic flow distribution. Based on the developed model, an investigation is conducted into the impact of pumping rates, fracturing fluid viscosity, and perforation parameters on the fracture propagation of multi-cluster fracturing. The study findings suggest that as reservoir heterogeneity increases, the distribution of rock strength becomes more uneven, resulting in a more complex morphology of fracture propagation. Higher pumping rates lead to elevated pressure within fractures, thereby facilitating the uniform propagation of multi-cluster fractures, particularly in reservoir characterized by medium to high heterogeneity. Increasing the viscosity of fracturing fluid can diminish the tortuosity of multi-cluster fracture propagation, albeit with a somewhat limited enhancement in uniformity. As reservoir heterogeneity intensifies, the interference between fractures escalates, necessitating a reduced number of perforations to heighten perforation friction and enhance the balanced propagation of multi-cluster fractures. This research offers theoretical guidance and a scientific foundation for the design of schemes and optimization of parameters in staged multi-cluster fracturing technology for horizontal wells in heterogeneous reservoirs.

Impact of Reservoir Heterogeneity on Bitumen Content in the Mackay River Oil Sands, Athabasca (Canada)

AbstractThe Lower Cretaceous Manville Group of Upper McMurray Formation is one of the main bitumen reservoirs in Athabasca. In this study, the relationship between reservoirs heterogeneity and bitumen geochemical characteristics were analyzed through core and microscopic observation, lab analysis, petrophysics and logging data. Based on the sedimentology framework, the formation environment of high‐quality oil sand reservoirs and their significance for development were discussed. The results indicate that four types lithofacies were recognized in the Upper McMurray Formation based on their depositional characteristics. Each lithofacies reservoirs has unique physical properties, and is subject to varying degrees of degradation, resulting in diversity of bitumen content and geochemical composition. The tidal bar (TB) or tidal channel (TC) facies reservoir have excellent physical properties, which are evaluated as gas or water intervals due to strong degradation. The reservoir of sand bar (SB) facies was evaluated as oil intervals, due to its poor physical properties and weak degradation. The reservoir of mixed flat (MF) facies is composed of sand intercalated with laminated shale, which is evaluated as poor oil intervals due to its poor connectivity. The shale content in oil sand reservoir is very important for the reservoir physical properties and bitumen degradation degree. In the context of regional biodegradation, oil sand reservoirs with good physical properties will suffer from strong degradation, while oil sand reservoirs with relatively poor physical properties are more conducive to the bitumen preservation.

Technology Focus: Sand Management (October 2024)

With the resurgence of drilling activities post-COVID-19, there is a growing interest in refining existing technologies and exploring new ones to discover cost-effective and reliable solutions for developing aged and more-challenging new reservoirs. Although approaches may vary slightly depending on the unique characteristics of reservoirs in different regions, the general trends are conceptually similar. Drilling longer wells, increasing the number of fracture stages, and completing multiple zones in complex stacked reservoirs, along with optimizing multilateral wells with sand control to enable long laterals in stacked reservoirs, have emerged as key focuses of the industry. Drilling longer wells introduces several challenges, including managing installation loads, ensuring proper wellbore cleanout, and ultimately producing effectively and uniformly from extended laterals that drill through heterogeneous reservoirs with varying sand facies. While liner flotation is effective in reducing installation loads and improving wellbore cleaning, it presents challenges when used in conjunction with conventional sand-control screens. Sand control and flow control are becoming more integrated to offer solutions for effective production from longer laterals. Flow segmentation helps prevent premature failures caused by gas or water breakthroughs or localized high rates causing erosion. Paper SPE 218074 is a good example of using flow-control devices to enhance the reliability and longevity of sand-control systems. Stacked reservoirs have always posed challenges in terms of zonal isolation and sand-control design. Higher fines content and silty sand with complex reservoir conditions leads to less interest in standalone screens because of the high risk of plugging and failure in such developments. Even though gravel packing is effective, it poses several technical and implementation challenges. The complexity of sandface completion, with varying sand sizes, pressures, and fluid properties, makes these wells particularly difficult to complete. Paper SPE 214914 offers a good case study of such a complex completion successfully implemented in the field. Despite all this, the fundamentals of screen design and implementation remain the same. Screen plugging remains one of the major challenges in the sand-control industry. Rigorous testing of sand-control media to verify retention properties, erosional resistance, integrity requirements for the installation-loading and lifelong-loading scenarios, and plugging resistance are critical aspects of any sand-control qualification. I strongly recommend reading paper IPTC 23690 for a detailed understanding of the screen-qualification process and the design of screens for target sand facies. Also, it is crucial to remember that no screen is completely immune to plugging. The unintended consequences of a change in drilling/completion fluid or cleanout process could lead to screen plugging. It is always important to test and validate the effect of any change in fluids or completion practices on sand-control performance. Recommended additional reading at OnePetro: www.onepetro.org. SPE 215070 A Comprehensive Review of Screen Plugging During Openhole Sand-Control Completions Installation: Causes, Consequences, and Best Practices by Maye Beldongar, SLB, et al. SPE 214934 Shunted Gravel-Pack Failures and How To Prevent Them by Carolina Latini, DuneFront, et al. SPE 215411 Performance of Bonded Bead Sand Screen as Remedial Sand Control in Highly Erosive Environment by Ashvin Avalani Chandrakant, Petronas, et al.

Understanding Lateral Permeability Variations in Heterogeneous Carbonate Reservoirs Using Logging-While-Drilling NMR, Microresistivity Imaging, and Azimuthally Oriented Formation Testing

Understanding Lateral Permeability Variations in Heterogeneous Carbonate Reservoirs Using Logging-While-Drilling NMR, Microresistivity Imaging, and Azimuthally Oriented Formation Testing