Reservoir Rocks Research Articles

Assessment of heavy oil recovery mechanisms using in-situ synthesized CeO2 nanoparticles

This project investigated the impact of low-temperature, in-situ synthesis of cerium oxide (CeO2) nanoparticles on various aspects of oil recovery mechanisms, including changes in oil viscosity, alterations in reservoir rock wettability, and the resulting oil recovery factor. The nanoparticles were synthesized using a microemulsion procedure and subjected to various characterization analyses. Subsequently, these synthesized nanoparticles were prepared and injected into a glass micromodel, both in-situ and ex-situ, to evaluate their effectiveness. The study also examined the movement of the injected fluid within the porous media. The results revealed that the synthesized CeO2 nanoparticles exhibited a remarkable capability at low temperatures to reduce crude oil viscosity by 28% and to lighten the oil. Furthermore, the addition of CeO2 nanoparticles to the base fluid (water) led to a shift in the wettability of the porous medium, resulting in a significant reduction in the oil drop angle from 140° to 20°. Even a minimal presence of CeO2 nanoparticles (0.1 wt%) in water increased the oil production factor from 29 to 42%. This enhancement became even more pronounced at a concentration of 0.5 wt%, where the oil production factor reached 56%. Finally, it was found that the in-situ injection, involving the direct synthesis of CeO2 nanoparticles within the reservoir using precursor salts solution and reservoir energy, led to an 11% enhancement in oil production efficiency compared to the ex-situ injection scenario, where the nanofluid is prepared outside the reservoir and then injected into it.

Oxidative Hydraulic Fracturing Fluid to Enhance Production from Source Rock Reservoirs

Summary The steep production declines generally observed after hydraulic fracturing in unconventional source rock reservoirs has been attributed to several potential causes. Recently, a new additive to the stimulation fluid system was proposed to extend economical longer-term production from these formations. Oxidizer-laden fracturing fluid systems are shown to create cracks and deep channels within the organic matter present in the source rock, such as kerogen, thereby increasing the source rock permeability and enhancing the hydraulic conductivity of the exposed fracture faces. To this end, the fluid design and recommendations for its application are illustrated herein. Oxidants composed of oxychlorine (ClOn−) and oxybromine (BrOn–) (where n = 0 to 4) are effective for kerogen depolymerization or degradation at depth. This study illustrates the beneficial effects of two specific oxidizers—sodium chlorite (NaClO2) and sodium bromate (NaBrO3)—on kerogen-rich source rock subjected to in-situ reservoir conditions. Source rock samples were cut and polished to test the oxidizer’s impact on the organic and inorganic regions. Scanning electron microscopy (SEM) and energy dispersive X-ray spectroscopy (EDS) were performed on the rock surface to identify specific organic matter features. The samples were then chemically treated with varying conditions of NaClO2 or NaBrO3 (concentration range: 0.013–0.054 M; temperature: 150°C; and time: 3–24 hours). Samples were returned to the scanning electron microscope for post-treatment analysis. Furthermore, the oxidants were packaged within a slickwater hydraulic fracturing fluid system for field application, and their effects on viscosity and friction reduction were also studied. SEM images and EDS maps of kerogen-rich rock samples observed before and after treatment with oxidizing fluid showed a series of cracks formed throughout the organic matter domains, where increasing the concentration of oxidizer in the treatment fluid showed a clear increase in the prevalence of cracks throughout the surface. The effect of time was also observed, as short treatment times resulted in porosity/permeability creation in the kerogen, though longer treatment times were associated with more severe degradation. Optimal conditions for NaClO2 and NaBrO3 concentrations in the additive fluid systems were different and will be herein highlighted. Each oxidizer (10–20 pptg concentration) was added to slickwater with variable friction reducer concentration (1 gpt, 2 gpt, and 4 gpt), and shear sweeps performed at both 70°F and 180°F. A negligible difference is observed between the viscosities of the base fluid and the fluid with either oxidant at low friction reducer concentration. Meanwhile, flow loop tests demonstrated that the oxidizer did not affect the friction reducer except to slightly boost the performance due to the salt effect on the polymer. Two strong oxidants, available as commodity chemicals, are shown to be effective in cracking kerogen and any present organic matter, thus creating permeable channels and enhancing the overall permeability of the exposed source rock fracture faces. Meanwhile, the proposed fracturing fluid additives display good compatibility with other slickwater fluid components, demonstrating the potential for universal usage in unconventional stimulations. The recommendations for its application as a fluid additive in slickwater are herein illustrated.

Study on Rock Interface Stability in the Heat Exchange Channel of the Horizontal Section of U-Shaped Wells in Hot Dry Rock

Enhanced Geothermal Systems (EGS) represent a promising direction for sustainable energy development, yet their efficiency and feasibility often suffer due to suboptimal heat extraction methods and interface instability in U-shaped wells. This study introduces an innovative volume encapsulation technology that aims to address these challenges. The proposed technology employs a combination of hydraulic fracturing and acidification to prepare the rock interface, followed by encapsulation using high-temperature liquid metal. Low-melting-point alloys are utilized as a heat exchange medium between the horizontal sections of the wells. This study meticulously analyzes the impact of formation stress, thermal shock stress, and liquid metal properties on rock interface stability. Advanced simulation tools and experimental setups were used to test the encapsulation process under various conditions. The application of liquid metal encapsulation demonstrated significant improvements in energy conversion efficiency and rock interface stability. In conditions simulating a dry and hot rock reservoir at depths up to 3000 m and temperature gradients reaching 2200 °C/m, the adjusted depth of horizontal sections and increased pumping pressure contributed to maintaining interface stability. The established failure criteria provide a robust theoretical foundation for the encapsulation process. Volume encapsulation technology using liquid metal not only enhances the operational efficiency of EGS but also stabilizes the rock interface, thereby increasing the feasibility of continuous geothermal energy extraction. This study offers valuable theoretical insights and practical guidance for future research and applications in geothermal energy technologies, creating new pathways for the efficient exploitation of geothermal resources.

A comprehensive study on optimizing reservoir potential: Advanced geophysical log analysis of zamzama gas field, southern indus basin, Pakistan

This study investigates the hydrocarbon and gas potential of the Pab Formation's Late Cretaceous reservoir in the Zamzama Gas Field (ZGF) situated in Pakistan's Southern Indus Basin (SIB). Vital insights to support Pakistan's escalating energy requirements. Petrophysical characteristics of the Pab Formation (PFm) zones of interest in the ZGF were determined by evaluating geophysical logs from four wells. Various techniques were employed to analyze the reservoir rock type (RRT), lithofacies, and spatial distribution of petrophysical parameters. The petrophysical assessment reveals that gas-bearing zones primarily consist of sandstone with intermittent shale layers. These reservoirs exhibit distinguishing attributes, including clean sand composition, high resistivity, total porosity (∅T), good permeability (K), minimal shale content (Vsh), and low water saturation (Sw). The total porosity ranges from 12% to 16%, permeability from 14 mD to 19 mD, water saturation levels between 34% and 44%, and hydrocarbon saturation (Sh) from 56% to 66%. The findings suggest significant gas reserves within the studied sand units of the Zamzama Block. Overall, this research provides a detailed and comprehensive understanding of reservoir characteristics, thereby increasing the potential for further hydrocarbon exploration and production in the study area.

The Dependence of Water and Gas Breakthrough on the Choice of Model Parameters in Naturally Fractured Reservoirs Using Sector and Full Reservoir Models

Assessing fractures in carbonate reservoirs is crucial due to their substantial impact on reservoir permeability. Understanding the characteristics of these fractures is vital for optimizing oil production. Additionally, extremely heterogeneous and anisotropic permeability distribution within the natural fractured reservoir is often caused by the complexity of a fracture network. Therefore, accurate reservoir modelling and simulation must be conducted in order to achieve ultimate recovery. In this paper, a sector model has been developed based on the studied example field, and its results are compared with the full reservoir model to find out the degree of resemblance between their outputs. The study area has four natural fracture compartments, with an average reservoir height of 95m and WOC and GOC depths of 685 m and 590 m, respectively. A dual-porosity and single-permeability modelling system was used to simulate the properties of the reservoir rock. This model was derived from the Petrel layercake model. A sensitivity analysis was also carried out to look into the relationships between field performance and the well. The outcomes of both models demonstrated that matrix permeability and fracture dimension had a significant impact on the early breakthrough of water and gas to comparable, huge extents. Other factors, such as aquifer size and WOC, show a moderate impact on water and gas breakthrough as well as final recovery.

Chemical and Physical Architecture of Macromolecular Gels for Fracturing Fluid Applications in the Oil and Gas Industry; Current Status, Challenges, and Prospects.

Hydraulic fracturing is vital in recovering hydrocarbons from oil and gas reservoirs. It involves injecting a fluid under high pressure into reservoir rock. A significant part of fracturing fluids is the addition of polymers that become gels or gel-like under reservoir conditions. Polymers are employed as viscosifiers and friction reducers to provide proppants in fracturing fluids as a transport medium. There are numerous systems for fracturing fluids based on macromolecules. The employment of natural and man-made linear polymers, and also, to a lesser extent, synthetic hyperbranched polymers, as additives in fracturing fluids in the past one to two decades has shown great promise in enhancing the stability of fracturing fluids under various challenging reservoir conditions. Modern innovations demonstrate the importance of developing chemical structures and properties to improve performance. Key challenges include maintaining viscosity under reservoir conditions and achieving suitable shear-thinning behavior. The physical architecture of macromolecules and novel crosslinking processes are essential in addressing these issues. The effect of macromolecule interactions on reservoir conditions is very critical in regard to efficient fluid qualities and successful fracturing operations. In future, there is the potential for ongoing studies to produce specialized macromolecular solutions for increased efficiency and sustainability in oil and gas applications.

Beetaloo gas, hydrogen and geothermal resources – insights from 3D basin modelling

The Beetaloo Sub-basin hosts a large proven shale gas resource, and this study demonstrates the opportunities for other low-emission energy sources including geothermal energy and natural hydrogen. CSIRO has developed a 3D basin model that predicts reservoir rock properties, pore pressure, composition of hydrocarbons and gas capacity of the Velkerri and Kyalla shales. Kinetic modelling also demonstrates that where Velkerri shale is overmature for hydrocarbons it potentially generated significant amounts of free molecular hydrogen. However, the proportion of this hydrogen currently preserved in the basin is unknown. The model also reveals considerable temperature anomalies around specific structural domains with heat flow up to 100 mW/m−2, and these are likely associated with radiogenic basement lithologies. These thermal domains are targets to further investigate geothermal and natural hydrogen resource potential in the Beetaloo Sub-basin.

Static contact angle, interfacial tension, and column height measurements for underground hydrogen storage

Geological porous media are key for large-scale hydrogen (H2) storage and production, where fluid interactions at interfaces and within rock formations are vital for effective gas containment. Although advancements have been achieved in comprehending structural trapping for estimating column height (CH), additional insights are required regarding how pore size impacts this estimation. Currently, CH estimates often consider seal rock potential, without including the capillary contribution from reservoir rock pore for structural trapping capacity assessment. This study measures the static contact angle (CA) on Wolfcamp (WC) Shale and interfacial tension (IFT) under modified drainage and imbibition conditions at temperatures of 30 and 50°C, pressures ranging from 500 to 3000 psia, and a salinity of 10 wt% sodium chloride. Subsequently, the static gas CH was calculated, accounting for contributions from the caprock pores alone and both the caprock and reservoir, to assess the structural sealing capacity of the caprock layer. The experimental procedures are comprehensively detailed in this paper. The outcome indicates that the static CA after drainage for H2)/brine/WC shale rises with pressure as the static CA after imbibition decreases. Both CAs decrease with increasing temperatures. For H2/brine systems, both drainage and imbibition IFTs decline with increasing pressure and temperature. Calculated CHs reveal that lower CAs substantially impact the gas trapping capacity beneath the caprock. In summary, this study highlights the preference for the drainage method in measuring IFT and CA to evaluate the potential structural trapping capacity of injected gas by the overlying caprock.

Microbial impact on basalt‐water‐hydrogen system: Insights into wettability, capillary pressure, and interfacial tension for subsurface hydrogen storage

AbstractHydrogen (H2) fuel is assessed to be a major component of sustainable energy systems in the net‐zero world. However, hydrogen storage is challenging and requires safe and environmentally friendly solutions like H2 geo‐sequestration. This study evaluates the effects of sulphate‐reducing bacteria (SRB) on H2 geological storage potential in the basalt rock. Fourier‐transform infrared spectroscopy (FTIR) findings show the presence of significant components, that is, O‐Si‐O and organic functional groups, that is, aromatics, amine salts, alkane, and cyclohexane in the basalt rock immersed in the nutrient solution without SRB. However, we found that C‐H stretching modes of organics with peaks at 1,465 cm−1 were observed. Consequently, amine salt (N‐H) (850–750 cm−1), solvent impurities (C‐H), and alkane spectrums are components of nutrient solutions and can be results of metabolic microbial activity that can influence on the surface of the basalt rock. Hence, these changes indicate the presence of microbial activity which might affect the surface chemistry of the rock leading to wettability alteration. We observed that the contact angle (θ) of brine‐H2 on the rock surface slightly changed from 500 to 4,000 psi pressure after the effect of bacteria at 50 °C. The wettability changed the surface of the rock from strong water‐wet to weak or intermediate water‐wet condition (i.e., θ < 75°) at 4,000 psi and temperatures 25 and 50 °C after the bacteria effect. The affiliation of brine water reduces on the rock surface with increasing temperatures and pressures, even without microbial influence. Additionally, we investigated interfacial tension and capillary pressure on SRB bacteria treated basalt which is not yet reported in the published work. Interfacial tension (IFT) and Pc of H2 were reduced by 19% and 65%, respectively at 50 °C and 4,000 psi after the bacteria effect. Hence, the above findings could help to answer the key factors of the reservoir rock including wettability, capillary pressure, and interfacial tension to plan a field‐scale H2 geo‐sequestration strategy under the influence of biotic life. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd.

The research on high efficiency water injection development of carbonate rock reservoir in the middle east

More and more attention has been paid to the waterflood development of carbonate reservoir in the Middle East with continuous expansion of the scale of carbonate reservoir development. Strong non-homogeneity of carbonate reservoirs results in serious conflicts between injection and production, causing low degree of water-driven control in the well network, and low degree of vertical mobilization. This article takes the main reservoir of an oil field in the Middle East region as an example, combining geological evaluation, dynamic analysis, and reservoir development strategies to study the effectiveness of water injection development in carbonate reservoirs. It shows that there is a correlation between pore type, oil-water relative permeability, and development method in the development of carbonate reservoirs. For reservoirs with matrix pores and micropores, water injection should be strengthened in the later stage of development; for reservoirs with dissolved pores and coarse pores, the iso-permeability point is relatively high, and the later development should focus on balanced water injection. Three different waterflooding models for formation development are designed to verify the feasibility of fine waterflooding schemes. The main differences are that one set of well patterns is combined injection and production, and three sets of well patterns are layered system waterflooding. The results show that the development effect in layered system waterflooding is the best. The daily production can be increased by about 16%, the cumulative oil production can be increased by about 8%, and the recovery factor can be increased by about 3%. Eventually, the stable oil and water control of carbonate reservoir can be realized.

Strontium isotopes and rare earth elements in terrestrial hot-spring deposits: Characterization and geothermal implications

Identifying geothermal reservoir rock types is fundamental in geothermal exploration, but the absence of active surface geothermal manifestations (especially hot springs) in blind geothermal systems makes this identification difficult. Nevertheless, blind geothermal systems may develop early-formed hot-spring deposits. As (bio-)chemical precipitate, these deposits may retain geochemical signatures of spring waters and thus provide insights into reservoir rock types. To assess their geothermal implications, the 87Sr/86Sr and rare earth elements + yttrium (REE + Y) characteristics of hot-spring deposits in two geothermal systems were investigated and compared with those of their reservoir rocks. Results showed relatively uniform 87Sr/86Sr values in hot-spring deposits within each system, but occasional 87Sr/86Sr contamination induced by exogenous detritus input was also observed. The amount of detritus input relates to the potential for interaction with surrounding soils/rocks and is thus environmentally controlled. Hot-spring deposits with high Sr concentrations showed greater 87Sr/86Sr contamination resistance than those with low Sr concentrations, revealing the influence of Sr concentration in hot-spring deposits on detrital 87Sr/86Sr contamination. The detritus input also influenced the REE + Y signatures of the hot-spring deposits, underscoring the necessity of contamination assessment before geochemical interpretation. Excluding samples with significant 87Sr/86Sr and/or REE + Y contamination, the remaining samples closely mirrored their respective reservoir rocks in terms of 87Sr/86Sr, with partial overlap in REE + Y signatures. This suggests that the 87Sr/86Sr and REE + Y characteristics of hot-spring deposits provide valuable insights into reservoir rock types. However, variations in 87Sr/86Sr or REE + Y compositions between some hot-spring deposits and corresponding reservoir rocks indicate additional influencing factors beyond reservoir rock types. Therefore, a comprehensive understanding of reservoir rock types requires integrated geochemical characterization, probably including 87Sr/86Sr, REE + Y, and other parameters. These findings underscore the potential of geochemical characterization of hot-spring deposits for identifying geothermal reservoir rock types, and this geochemical approach can complement geological and geophysical data to improve exploration efficiency, especially in blind geothermal systems.

Effect of crack density on crack initiation and damage for high confining pressure using wave velocities

The study of progressive failure of reservoir rocks is very important for the stability analysis of ultra-deep boreholes. The progressive failure can be characterized by the crack initiation stress (CI), crack damage stress (CD) and peak stress (Peak), which is controlled by the evolution of cracks in rock and is significantly affected by confining pressure. To explore the effect of high confining pressure and initial crack on the progressive failure, the initial crack density of 121 sedimentary rock samples was characterized by acoustic waves, and the progressive failure under different confining pressures was analyzed. Experiments show that the ratios of CI to Peak (CI/Peak) and CD to Peak (CD/Peak) increase significantly with confining pressure, which is agreement with the existing conclusion from low confining pressure (0–52 MPa), but those decrease for high confining pressure (68–85 MPa) above critical point of sandstone. The CI/Peak and CD/Peak decrease with increase of initial crack density, which is sensitive to confining pressure but independent of rock type and grain size. The CD of sandstone is pertinent to the friction coefficient of cracks. These results laid a foundation for analyzing the evolution mechanism of wellbore damage and predicting the timing of wellbore instability in ultra-deep wells.

Surface wetting characterization in pore-scale multiphase flow simulations: A Ketton carbonate case study

Direct numerical simulations are commonly applied to X-ray computed microtomography images of porous rocks to measure petrophysical properties, such as relative permeability. To complement and/or expand laboratory data with useful simulations, such simulations need to reflect the true wetting condition of reservoir rock. It is therefore important to investigate approaches for assigning surface wetting conditions in pore-scale multiphase flow simulations. Two-phase Lattice-Boltzmann simulations are conducted on a Ketton carbonate image using different effective wetting models and then compared to pore-scale experimental data on the same rock, which is published elsewhere in (Scanziani et al., 2018). Two different wetting models are established based on the aging of the Ketton sample with crude oil at connate water saturation. Model 1 provides uniform wetting on all oil treated surfaces. Model 2 attempts to capture the multiscale nature of carbonate by allowing for spatially varying wetting conditions on oil treated surfaces based on local microporosity. Assessment criteria are based on pore-scale morphological measures, which include oil surface area coverage, oil phase topology, fluid/fluid curvatures, and contact angles. Overall, Model 1 with an assigned contact angle of greater than +10° above the geometrically measured contact angle from the experimental data provided the best results based on our assessment criteria.

Sedimentology, depositional processes, and sequence stratigraphy of deep lacustrine fine-grained sedimentary rocks in the lower Oligocene Xiaganchaigou Formation, Qaidam Basin, Northwestern China

Lacustrine deep-water fine-grained sedimentary rocks are characterized by high heterogeneities in lithology and lithofacies stacking patterns, controlled by sediment supply and lake level fluctuation. Despite their vital roles as source and reservoir rocks of unconventional oil and gas play, depositional processes and sedimentary sequence of lacustrine fine-grained sedimentary rocks are poorly understood compared to their extensively studied deep marine counterparts. Here, we studied lithofacies, transportation and depositional processes, depositional environments, and sedimentary cycles of deep-water fine-grained deposits of the Lower Oligocene Xiaganchaigou Formation from cored wells in the western Qaidam Basin. Nine lithofacies that stack repetitively in 6–18 m thick sedimentary cycles are identified based on petrographic observation, geochemical analysis, and scanning electron microscopy. The regressive systems tract of a sedimentary cycle is composed of detrital-rich massive fine sandstone deposited by debris flows and thin-bedded fine sandstone deposited by high-density turbidity currents. The transgressive systems tract is dominated by laminated carbonate-rich mudrock facies deposited by low-density turbidity currents. A complete sedimentary cycle is interpreted to represent a transgressive-regressive cycle controlled by fifth-order lake-level variation. Coarse-grained detrital-rich debrite and high-density turbidite were deposited in the proximal sublacustrine fan and channel during lake-level regression, with sediments mainly supplied by terrigenous siliciclastic input. Carbonate-rich low-density turbidites are deposited primarily in the distal sublacustrine fan during lake-level transgression. Thin-laminated carbonate-rich mudrock facies with high organic matter abundance and well-developed laminae-induced fractures are considered both source rocks and target reservoirs of the upper Xiaganchaigou Formation.

Combined effects of high temperature and lithology on the tensile mechanical damage and fracture surface morphology of reservoir rocks

Combined effects of high temperature and lithology on the tensile mechanical damage and fracture surface morphology of reservoir rocks

Rock fines breakage by flow-induced stresses against drag: geo-energy applications

The paper presents a strength-failure mechanism for colloidal detachment by breakage and permeability decline in reservoir rocks. The current theory for permeability decline due to colloidal detachment, including microscale mobilisation mechanisms, mathematical and laboratory modelling, and upscaling to natural reservoirs, is developed only for detrital particles with detachment that occurs against electrostatic attraction. We establish a theory for detachment of widely spread authigenic particles due to breakage of the particle-rock bonds, by integrating beam theory of particle deformation, failure criteria, and creeping flow. Explicit expressions for stress maxima in the beam yield a graphical technique to determine the failure regime. The core-scale model for fines detachment by breakage has a form of maximum retention concentration of the fines, expressing rock capacity to produce breakable fines. This closes the governing system for authigenic fines transport in rocks. Matching of the lab coreflood data by the analytical model for 1D flow exhibits two-population particle behaviour, attributed to simultaneous detachment and migration of authigenic and detrital fines. High agreement between the laboratory and modelling data for 16 corefloods validates the theory. The work is concluded by geo-energy applications to (i) clay breakage in geological faults, (ii) typical reservoir conditions for kaolinite breakage, (iii) well productivity damage due to authigenic fines migration, and (iv) feasibility of fines breakage in various geo-energy extraction technologies.

Introducing the area under stress–velocity curve: Theory, measurement and association with rock properties

AbstractSince many years ago, ultrasonic velocity has been used to investigate the physical and mechanical behaviour of rocks, thereby playing an important role in reservoir characterization and seismic interpretation. In order to develop the knowledge of ultrasonic tools, we performed a noble analysis on the ultrasonic behaviour of rocks under confining stress and evaluated a distinctive property of porous media that is measured as the area under the stress–velocity curve (here defined as S*). We further investigated its relationship with elastic and mechanical behaviours of rock. To validate the theoretical framework developed in this work, 20 core plugs from various rock units with complex microstructures were subjected to triaxial compressional tests to calculate their area under the curve. Calculations were made for crack‐closing, elastic and post‐elastic stages (e.g. pore collapse) along the ultrasonic velocity–stress curve. Moreover, the selected samples had their microstructure investigated by thin‐section studies to quantify their porosity and pore type. The results were analysed to check for the effect of pore type on S* in different stages of the stress–velocity curve. Based on the outputs of the analysis of variance and Pearson's correlation coefficient analysis, the curve had its shape and underlying area closely related to the porosity and pore geometry. Indeed, the results showed that the shale and sandstone with micro cracks and carbonate with stiff pores correspond to smaller and larger areas under the curve in crack‐closing and inelastic stages, respectively. Cross‐correlating the results to compressibility (inverse of bulk modulus), it was figured out that the calculated area under curve was well consistent with the compressibility. In addition, S* represents both static and dynamic behaviours of the rock, and the results revealed that the shape and curvature of the stress–velocity curve give valuable information about the rock microstructure. Another finding was the fact that the type of fluid and wave velocity seemingly affect the S*. Our findings can help interpret wave velocity behaviour in reservoir rocks and other stressful porous media.

Permeability modelling in a highly heterogeneous tight carbonate reservoir using comparative evaluating learning-based and fitting-based approaches

Permeability modelling is considered a complex task in reservoir characterization and a key component of reservoir simulation. A common method for permeability modelling involves performing static rock typing (SRT) using routine core analysis data and developing simple fitting-based mathematical relations that link permeability to reservoir rock porosity. In the case of carbonate reservoirs, which are associated with high heterogeneities, fitting-based approaches may fail due to porosity–permeability data scattering. Accurate modelling of permeability using petrophysical well log data seems more promising since they comprise a vast array of information about the intrinsic properties of the geological formations. Furthermore, well log data exhibit continuity throughout the entire reservoir interval, whereas core data are discrete and limited in availability and coverage. In this research work, porosity, permeability and log data of two oil wells from a tight carbonate reservoir were used to predict permeability at un-cored intervals. Machine learning (ML) and fitting models were used to develop predictive models. Then, the developed ML models were compared to exponential and statistical fitting modelling approaches. The integrated ML permeability model based on Random Forest method performed significantly superior to exponential and statistical fitting-based methods. Accordingly, for horizontal and vertical permeability of test samples, the Root Mean Squared Error (RMSE) values were 3.7 and 4.5 for well 2, and 1.7 and 0.86 for well 4, respectively. Hence, using log data, permeability modelling was improved as it incorporates more comprehensive reservoir rock physics. The outcomes of this reach work can be used to improve the distribution of both horizontal and vertical permeability in the 3D model for future dynamic reservoir simulations in such a complex and heterogeneous reservoir system.

Overcoming Gassmann's equation limitations in reservoir rocks

Velocities of low-frequency seismic waves and, in most rocks, sonic logging waves depend on the compressibility of the undrained rock, which is conventionally computed from the drained rock compressibility using Gassmann's equation. Although more comprehensive and accurate alternatives exist, the simplicity of the equation has made it the preferred fluid substitution model for geoscience applications. In line with recent publications, we show that Gassmann's equation strictly applies only to rocks with a microhomogeneous void space microstructure that is devoid of cracks and microcracks. We use a rock physics model that separates the respective compliance contributions of pores and cracks on dry (drained) moduli and show that Gassmann's model does not apply to rocks with measurable crack density. A fourth independent bulk modulus (in addition to the bulk moduli of the mineral matrix, dry frame, and saturating fluid) is required to take the effect of cracks into account and perform fluid substitution modeling for rocks with pores and cracks more accurately than prescribed by Gassmann's equation. Therefore, we propose combining the Vernik-Kachanov model with Brown-Korringa's equation for more reliable modeling of undrained bulk compressibility for reservoir rocks with measurable crack density. To conclude, a practical quantification of the applicability of Gassmann's equation based on the combined effects of crack density and stress sensitivity is proposed.

Fundamental principles and results of deep well lining

The review of the theory and practice of the special technological fluids application is analyzed. On the example of a specific borehole, with an actual vertical depth of 3287 m, intended for opening horizons B-17v, B-17n and project B-21, measures to clarify the filtration and capacity properties of reservoir rocks, increase production volumes are considered of hydrocarbons and accelerating the rate of selection of mining reserves. Testing in the interval 3364 - 3337.6 m of the B-21 horizon by using a set of test tools KVI-95, objectively proved that the specified object is characterized as penetrating, gas-saturated, the activity of which is reduced by contamination of the near-outbreak zone of the seam. As a method of determining clogging, a cut of the working end of the core with a length of 1 mm was applied. According to the results of the interpretation of the materials of the geophysical research of the specified borehole, it was established that the seam fluid comes from the interval 3339 - 3344 m. The paper determined that a promising way to solve the issue of high-quality cementing is the application of composite tamponage systems in combination with advanced preparation methods of borehole shaft.