Reservoir Production Research Articles

Research on productivity of stimulated natural gas hydrate reservoir

Natural gas hydrate (NGH) is a prospective clean energy. Conventional development method of the NGH reservoir by pressure drop in vertical well faces the problems of limited stimulated reservoir volume, low production efficiency, and low conductivity. At present, pressure drop production in various well types and stimulation treatments such as hydraulic fracturing in fracable NGH reservoirs have become the focus. The effects of pressure drop production in vertical well, horizontal well, radial wells, and hydraulic fracturing in vertical and horizontal wells in NGH reservoirs were simulated with HydrateResSim. We simulated the productivity of NGH reservoir for 1000 days with several types of development mode. The productivity is highest in horizontal well staged fracturing (5 stages), followed by pressure drop production in horizontal well, fractured vertical well (single fracture), and radial well (16 holes). The worst effect is obtained through production by pressure drop in single vertical well. The optimal effects were obtained with the fracture spacing of 58 m, the fracture half-length of 100 m and the conductivity of 30 μm2 cm. The horizontal well multi-cluster fracturing significantly enlarges the stimulated area and provides channels for gas migration and enhances productivity.

Lithologic controls on reservoir quality and production trends in the Pettet Formation, Rusk County, east Texas

Lithologic controls on reservoir quality and production trends in the Pettet Formation, Rusk County, east Texas

The Effect of Fracturing Fluids Types on Reservoir Fracture Geometry, Production, and Net Present Value

The Effect of Fracturing Fluids Types on Reservoir Fracture Geometry, Production, and Net Present Value

Physical simulation study on production characteristics and mechanism of connate water in gas reservoirs

The late-stage development of gas reservoirs often encounters the paradox of significant remaining formation pressure coupled with low wellhead pressure, which indicates small drainage volume, low gas production rate, and low recovery efficiency, reducing gas supply and economic benefit. Owing to the lack of experimental research, the reasons behind this contradiction between gas production and producing pressure differential are unclear. The key factors affecting the development outcomes are reservoir permeability and initial water saturation, while the evaluation parameters include gas and water production rates, reservoir pressure, and recovery efficiency. Based on the characteristic properties of typical gas fields, physical simulation experiments of constant-rate gas production are conducted on spliced long cores with average permeabilities of 2.300, 0.486, and 0.046 millidarcy (mD). Furthermore, leveraging the multi-point embedded pressure measurement technique, the pressure drawdown propagations and the macroscopic and microscopic characteristics of connate water production at the initial water saturations of 0%, 20%, 40%, and 55% are investigated. By connate water, we mean water that occurs naturally within the pores of rock. Pre- and post-experiment core weighing and nuclear magnetic resonance testing are performed. In addition to the mercury injection tests, the results indicate that during gas reservoir depletion, connate water primarily stems from macropores and mesopores, with micropores and nanopores capturing water through capillary imbibition. Moreover, lower permeability and higher initial water saturation lead to greater pressure gradients, increased connate water production, and reduced recovery efficiency. Reservoirs with permeabilities below 0.1 mD are significantly affected by connate water, exhibiting steep pressure profiles. Owing to connate water, the near-wellbore pressure quickly decreases, while distant reservoir pressure barely decreases, implying a limited drainage area. To enhance the recovery efficiency, measures like infill drilling and reservoir stimulation are recommended for low-permeability gas reservoirs.

Исследование обводненности добывающих скважин Демьяновского месторождения

The article is devoted to the problem of waterlogging of borehole products during the extraction of hydrocarbon raw materials, which arises for various reasons. This may be due to the geological structure of the field, non-compliance with the operating modes of wells, poor-quality cementing of backwater spaces, etc. Waterlogging leads to undesirable consequences: reduction of oil and gas production and occurrence of emergency situations. The problems of waterlogging of borehole products are solved using various methods: the use of chemical reagents to reduce the viscosity of water, the use of technical solutions for separating oil and water, repair and insulation works, etc. The Demyansk oil field is considered: its geological features, geological exploration, the main indicators of well operation. The analysis of the dynamics of well flooding and a comparison of the design and actual indicators of the development of the Demyanovskoye field as of 01.01.2017 are presented. The actual dynamics of well flooding is also presented, the reasons for the rapid flooding of the production of wells of the Demyanovsky place of birth are considered. As a result of the analysis of the actual data obtained during the operation of the field, it was established that the main reason for the rapid flooding of the reservoir production of the field is the transfer of wells to a mechanized method of operation, which, in turn, leads to an increase in depression on the formation. It is concluded that the forecast indicators of well flooding calculated on the hydrodynamic model differ significantly from the real ones, and attention is also drawn to the need to select the optimal depression when transferring wells to a mechanized production method to prevent rapid product flooding.

Analysis of Potential Environmental Risks in the Hydraulic Fracturing Operation in the “La Luna” Formation in Colombia

This article presents an in-depth analysis of potential environmental risks associated with hydraulic fracturing operations within the “La Luna” formation in Colombia. Using the Conesa methodology, it assesses the environmental impacts of unconventional reservoir production in Colombia, including water usage, chemical additives, air emissions, and the potential for groundwater contamination. This study incorporates comprehensive data on geological characteristics, operational procedures, and environmental conditions specific to the region. This analysis highlights the need for a proactive approach to managing potential environmental risks associated with hydraulic fracturing in Colombia. The findings underscore the importance of implementing robust regulatory measures, comprehensive monitoring systems, and the industry’s best practices to mitigate and prevent adverse environmental impacts. This research contributes to the ongoing global dialogue on the environmental implications of hydraulic fracturing in regions with sensitive ecological conditions. The environmental impacts of unconventional reservoirs are widely recognized as a general consensus; however, the absence of applied studies with the rigor of an explicit methodology in Andean countries highlights the need for specific research in this region. This article addresses this gap by proposing a detailed and structured methodology to assess and mitigate environmental impacts in unconventional reservoirs. Emphasizing the importance of knowing the characteristics of reservoir fluids, this research highlights that this critical information is only revealed by drilling exploration wells and PVT (pressure, volume, and temperature) analysis. Obtaining this data is crucial for shaping specific mitigation measures, thus allowing for the formulation of a robust environmental management plan tailored to the conditions of the reservoirs in the Andean region. This precise and contextualized approach contributes to closing the knowledge gap and promotes more sustainable practices in the exploitation of unconventional reservoirs in this specific geographical context. The methodology used in this study proved its effectiveness by accurately quantifying the risks associated with each of the environmental alterations inherent to the hydraulic fracturing process in the La Luna formation. The results obtained allowed for the identification of the critical points most susceptible to environmental impacts, serving as a solid basis for the elaboration of an environmental management plan. This strategic approach not only enabled the delineation of specific mitigation measures but also facilitated the selection of the most appropriate locations for the implementation of the plan, maximizing the effectiveness of corrective actions. It is noteworthy that the successful application of the Conesa methodology in this unconventional reservoir context evidences the versatility and applicability of this approach, consolidating it as a valuable tool for environmental assessment and effective planning in the hydraulic fracturing industry.

Nodal Analysis of Naturally Flowing Wells in Faihaa Oil Field, Yamama Formation

This study focuses on the Yamama Formation, a significant carbonate reservoir in southern Iraq that is one of the most important productive reservoirs in the region. The Formation is characterized by porous limestone interspersed with thin layers of argillaceous and tight limestone. The Yamama reservoir in the Faihaa oil field is divided mainly into four units; YA, YB, YC, and YD. YA and YB units are considered to be the most important oil-bearing subunits due to their good petrophysical properties. The main objective of the study is to determine the optimum production rates of four naturally flowing wells in the Faihaa oil field using the Inflow Performance Relationship and Vertical Lifting Performance curves. The study investigates four critical parameters; tubing size, water cut, reservoir pressure, and wellhead pressure, and their impact on well performance. The study finds that wellhead pressure is the primary determinant of well performance, and deviations from the original tubing size have adverse effects on well performance. An increase in water cut beyond the recommended threshold, coupled with a reduction in reservoir pressure, results in decreasing well performance. The study underscores the importance of careful monitoring and analysis of these parameters to sustain and enhance well performance in the Faihaa oil field, providing valuable insights for well operators and petroleum engineers. The study's findings can be used to optimize well performance and increase oil production rates, with significant implications for the petroleum industry.

Impact of Petrophysical and Mechanical Properties on Engineering Classification of the Facha Reservoir Rocks, Western Sirte Basin, Libya

Rock identification and classification have contributed to the enhancement of drilling oil wells and production reservoir performance. Therefore, understanding the properties of reservoir rocks is a major concern in the petroleum industry. In this context, Young’s modulus and uniaxial compressive strength are major mechanical rock properties essential for defining the engineering classification and modulus ratio of rocks. However, these parameters are used in order to examine the impact of the petrophysical properties on mechanical strength in the Facha member (reservoir) of the Gir Formation in the western central of Sirte Basin, oilfields of central Libya. Dolomite, limestone, dolomitic limestone, and anhydrite are the main lithofacies rock components of this reservoir, as well as of a third member of the Gir Formation (Lower Eocene). Young’s modulus and uniaxial compressive strength were computed from sonic and bulk density well logs data from six wells in four different oil fields. This oil-rich reservoir has an average thickness of 104 m, an average total porosity of 16%, and argillaceous material content (clay) of 4%. According to the engineering classification chart of Deere and Miller, the Facha reservoir rocks have a very low class (E < 27.5 Mpa) to high strength class (B ≈ 110-220 Mpa) and have a medium-to-high modulus ratio (M ≈ 200–500 and H ≈ 500). Generally, the diagenesis process, for instance dolomitization, affected both the strength and the modulus ratio.

Experimental study on the Klinkenberg effect for gas permeability in carboniferous shales, Eastern Qaidam Basin, China

It is crucial to understand the conditions and influencing mechanisms of shale gas slip effect for predicting the productivity of shale gas reservoirs. This study focuses on the Carboniferous Hurleg Formation shales in the eastern Qaidam Basin and conducts gas permeability tests using different gases (He/N2), as well as geochemical and pore-structure tests. The slip behavior of different gases in micro- and nanopores as well as the anisotropy of gas permeability were analyzed and discussed. The results show that helium permeability is 1.81–3.56 times higher than nitrogen permeability, with a greater difference at lower pore pressures. These permeability differences are attributed to variations in gas molecule size and slip effects. Specifically, the slip effect of helium gas has a greater contribution to permeability at lower pore pressures, with a helium slip factor averaging 2.79 times that of nitrogen. The effective pore size of shale, calculated based on the helium slip factor, is 0.74 to 1.51 times larger than when nitrogen is used, with an average of 1.67 times. Helium molecules have smaller diameters and longer average molecular free paths, resulting in a more pronounced slip effect compared to nitrogen. While helium does not adsorb, nitrogen exhibits some adsorption, causing radial expansion during gas penetration. Furthermore, when testing with different gases, the horizontal permeability (S043∥; S052∥) is higher than the vertical permeability (S043⊥; S052⊥). The anisotropy of permeability is controlled by the pore system formed by the arrangement and combination of minerals. Calcium-rich samples (S052) tend to exhibit higher anisotropy compared to calcite-rich samples (S043). The effective pore size in the vertical sample is larger than that in the parallel sample, and the gas slip effect is significantly greater in the vertical sample. These findings provide valuable data for future studies on shale gas slip effects and productivity prediction.

Employing Statistical Algorithms and Clustering Techniques to Assess Lithological Facies for Identifying Optimal Reservoir Rocks: A Case Study of the Mansouri Oilfields, SW Iran

The crucial parameters influencing drilling operations, reservoir production behavior, and well completion are lithology and reservoir rock. This study identified optimal reservoir rocks and facies in 280 core samples from a drilled well in the Asmari reservoir of the Mansouri field in SW Iran to determine the number of hydraulic flow units. Reservoir samples were prepared, and their porosity and permeability were determined by measuring devices. The flow zone index (FZI) was calculated for each sample using MATLAB software; then, a histogram analysis was performed on the logarithmic data of the FZI, and the number of hydraulic flow units was determined based on the obtained normal distributions. Electrical facies were determined based on artificial neural network (ANN) and multi-resolution graph-based clustering (MRGC) approaches. Five electrical facies with dissimilar reservoir conditions and lithological compositions were ultimately specified. Based on described lithofacies, shale and sandstone in zones three and five demonstrated elevated reservoir quality. This study aimed to determine the Asmari reservoir’s porous medium’s flowing fluid according to the C-mean fuzzy logic method. Furthermore, the third and fourth flow units in the Asmari Formation have the best flow units with high reservoir quality and permeability due to determining the siliceous–clastic facies of the rock units and log data. Outcomes could be corresponded to the flow unit determination in further nearby wellbores without cores.

Impacts of geomechanical damage on waterflood-induced fracture propagation in deeply deposited tight oil reservoirs

Waterflood-induced fractures can enhance the production of deep tight oil reservoirs. However, if waterflood-induced fractures propagate fast, they connect injection wells to production wells earlier, inhibiting the production of tight oil reservoirs. In the present research, the fast propagation mechanism of waterflood-induced fractures was mainly investigated. The changes in sandstone mechanical properties by water were investigated by laboratory experiments, and the relationship of the geomechanical damage of sandstones with water saturation was quantified. Flow-geomechanics-coupled numerical simulations were performed to analyze the impacts of water flooding on stress distribution in a deeply deposited tight oil reservoir. Based on the fracture mechanics theory, the propagation length of the waterflood-induced fracture was calculated and the characteristics of waterflood-induced fracture propagation were analyzed. Experimental results revealed that water changed the mineral composition and microscopic structure of sandstones. This phenomenon decreased the Young’s modulus and tensile strength of sandstones and increased the Poisson’s ratio. The changing magnitude of these properties increased with the rise of water saturation, and the maximum changing magnitude reached 70%. The water saturation distribution became heterogeneous after waterflooding, causing a heterogeneous distribution of mechanical properties. The stress around the fracture tip and the fracture propagation length were significantly affected by these property changes. After the geomechanical damage, the fracture propagation pressure decreased by about 20%. Moreover, the initial fracture length enhanced the propagation length of the waterflood-induced fracture. These results suggest that the propagation of waterflood-induced fractures becomes more significant during waterflooding; thus, the injection pressure should be reduced to avoid fast fracture propagation.

Numerical study of the mechanisms of nano-assisted foam flooding in porous media as an alternative to gas flooding

Oil reservoirs are nearing maturation, necessitating novel enhanced oil recovery (EOR) techniques to meet escalating global energy demands. This demand has spurred interest in reservoir production analysis and forecasting tools to enhance economic and technical efficiency. Accurate validation of these tools, known as simulators, using laboratory or field data is pivotal for precise reservoir productivity estimation. This study delves into the application of nanoparticles in foam flooding for mobility control to improve sweep efficiency. Foam generation can occur in-situ by simultaneous injection of surfactants and gas or through pre-generated foam injection into the reservoir. In this work, a series of systematic simulations were run to investigate how much injected fluids can reduce gas breakthrough while also increasing oil recovery. Subsequently, we analyzed the most effective optimization strategies, considering their economic limits. Our primary objective is to numerically model nanofoam flooding as an innovative EOR approach, synergizing foam flooding mechanisms with nanotechnology benefits. In this work, modeling of nanoparticles in foam liquid was represented by the interfacial properties provided to the injection fluid. Additionally, we simulated Water-Alternating-Gas (WAG) injection schemes across various cycles, comparing their outcomes. Our results showed that nanofoam injection achieved a higher recovery factor of at least 38% and 95% more than WAG and gas injections, respectively. The superior efficiency and productivity of foam injection compared to WAG and gas injection suggest an optimal EOR approach within the scope of our model. These simulated optimization techniques contribute to the future development of processes in this field.

Using automatic model calibration for 3D morphological simulations: a case study of the Bodendorf reservoir flushing

AbstractReservoir sedimentation poses a significant challenge to water resource management. Improving the lifespan and productivity of reservoirs requires appropriate sediment management strategies, among which flushing operations have become more prevalent in practice. Numerical modeling offers a cost-effective approach to assessing the performance of different flushing operations. However, calibrating highly parametrized morphological models remains a complex task due to inherent uncertainties associated with sediment transport processes and model parameters. Traditional calibration methods require laborious manual adjustments and expert knowledge, hindering calibration accuracy and efficiency and becoming impractical when dealing with several uncertain parameters. A solution is to use optimization techniques that enable an objective evaluation of the model behavior by expediting the calibration procedure and reducing the issue of subjectivity. In this paper, we investigate bed level changes as a result of a flushing event in the Bodendorf reservoir in Austria by using a three-dimensional numerical model coupled with an optimization algorithm for automatic calibration. Three different sediment transport formulae (Meyer-Peter and Müller, van Rijn, and Wu) are employed and modified during the calibration, along with the roughness parameter, active layer thickness, volume fraction of sediments in bed, and the hiding-exposure parameter. The simulated bed levels compared to the measurements are assessed by several statistical metrics in different cross-sections. According to the goodness-of-fit indicators, the models using the formulae of van Rijn and Wu outperform the model calculated by the Meyer-Peter and Müller formula regarding bed patterns and the volume of flushed sediments.

Integrated characterization of deep karsted carbonates in the Tahe Oilfield, Tarim Basin

Abstract As transport channels of oil and gas, fracture networks can greatly improve reservoir seepage, which is of great significance to the hydraulic fracturing and hydrocarbon deposit exploitation in petroleum science and engineering. In this paper, our target reservoirs are deep karsted carbonates at depths of >6000 m and highly heterogeneous, leading to complex seismic responses with weak energy and low resolution. Therefore, it is challenging to predict the spatial distribution of a carbonate fracture-cavern reservoir and to characterize its delicate structure. We present a characterization method for an excellent fracture description by integrating several attribute results on 3D seismic field data. First, we use a noise elimination method to remove the noise interference in seismic data without damaging the fault structure characteristics. Next, we propose a novel spatially windowed 2D Hilbert transform-based operator to perform volumetric edge detection on 3D seismic field data. Then, the volumetric edge results are co-rendered with other seismic geometric attributes to generate multi-attribute fusion results for a comprehensive prediction that can excellently delineate geologic anomalies at different scales in deep carbonates. The results indicate that integrating several scale attributes can obtain more rich geological discontinuity and reveal more subtle fractures than using single attribute. The multi-attribute fusion results can effectively delineate some small-medium-sized faults, and they provide practical support for the exploration and production of Tahe carbonate fracture-cavern reservoirs.

Association rules mining for long uptime sucker rod pumping units

The uptime of sucker rod pumping units (SRPUs) varies significantly due to differences in geological reservoir conditions, as well as design and operation parameters of the SRPUs. Conventional approaches encounter challenges in accurately quantifying the intricate interplay of these factors with uptime. This study investigates the application of association rules mining in exploring reliable measures in long uptime SRPUs. We create an uptime dataset for 5789 sucker rod pumping wells with 16 features encompassing reservoir conditions, production characteristics, SRPUs design, operational settings, and uptime. A novel algorithm is proposed to mine association rules between uptime and other features, yielding over 1,000,000 rules. These rules reveal relationships and impacts on long uptime. By following these rules, adjustments can be made to improve the uptime of SRPUs through alterations in design and operational parameters. Two case studies were presented to illustrate that by adjusting the design and operational parameters of SRPUs based on the association rules, the probability of improved operational performance can be increased by 30 % and 8 % respectively. This study explores the association rules of long uptime SRPUs from a data-driven paradigm, providing scientific guidance for subsequent oil well design. The research methodology is also valuable for other mechanical equipment.

Cooling Damage Characterization and Chemical-Enhanced Oil Recovery in Low-Permeable and High-Waxy Oil Reservoirs

The well productivity of high-waxy reservoirs is highly influenced by temperature changes. A decrease in temperature can cause the precipitation of wax from the crude oil, leading to a decrease in the formation’s drainage capacity and a drop in oil production. In this study, the wax precipitation of crude oil is characterized by rheological properties tests and differential scanning calorimetry (DSC) thermal analysis. The wax damage characteristics of cores and the relative permeability curves at different temperatures were investigated through coreflood experiments. Furthermore, nanoemulsion is selected as a chemical agent for injection fluid. The nuclear magnetic resonance (NMR) scanning technique is used to investigate the effects of oil recovery enhancement at different pores by increasing temperature and adding nanoemulsion. By comparing the changes in T2 spectra and the distribution pattern of residual oil before and after liquid injection, the results have shown that both increasing temperature and adding nanoemulsion have a significant effect on oil recovery. The improvement of micropores is less pronounced compared to macropores. The produced oil mainly comes from the large pores. When the temperature is lower than the crude oil dewaxing point temperature, there is a serious dewaxing plugging phenomenon in the pores. Additionally, by observing the pattern of residual oil distribution at the end of the NMR online drive, it is hereby classified into wax deposition retention type, weak water washing retention type, and immobilized type, each with its own distinct characteristics. Wettability alteration and interfacial tension reduction can help to improve the drainage capacity of high-wax oil reservoirs, which is the main mechanism of nanoemulsion for enhanced oil recovery. These findings are highly valuable for enhancing the comprehension of the impact of highly waxed crude oils on drainage capacity and the ultimate oil recovery rate, particularly in relation to wax precipitation deposition.

Diagenetic imprints in the reservoirs of Agbada Formation, Niger Delta Basin: Implication for reservoir quality and appraisal of calcite cement

The main exploration targets for hydrocarbons in the Niger Delta Basin are within the Agbada sandstone reservoirs. The current study utilizes a multitechnical approach (SEM-MLA, SEM-EDS, XRD and LA-ICP-MS) to evaluate the roles of framework composition and diagenetic processes, particularly calcite cementation on reservoir quality in Miocene intervals of the Agbada Formation sandstone, Niger Delta Basin. Petrographic analysis reveals that the sandstones are feldspatho-quartzose to quartzose sandstones, with a preponderance of quartzose sandstones. The overall diagenetic imprints suggest minimal compaction and lack of pervasive cement, which have contributed significantly to the high porosity. Although the degree of mechanical compaction is generally low, it has comparatively exercised a better control on porosity than the growth of cement, excluding some intervals with considerable cementation (siderite and ferroan calcite) where compactional porosity-loss was minimal. The occurrence of ferroan calcite cement (CaCO3 = 95.9 ± 0.4, MgCO3 = 0.8 ± 0.1, FeCO3 = 2.9 ± 0.2 mol%) is generally small, probably discontinuous and unlikely to represent significant barriers to fluid flow with their localized influence, but understanding their locally significant influence may still contribute to building good reservoir models. Petrographic observations suggest that the precipitation of “poikilitic” calcite was early, but the shale normalized REY patterns do not mimic seawater patterns (Y/Ho ratios; 36.3 ± 1.6) due to possible contributions from clastic or detrital grains and/or incorporation of particulate matter that can preferentially scavenge LREEs from the overlying water column. A possible concern during reservoir production is the occurrence of clay mineral matrix (mostly kaolinitic) anticipated to cause the production of fines and formation damage, but this can be mitigated with proper reservoir management.

Wormholing behavior in matrix acidizing in vuggy, naturally fractured carbonate reservoirs

In vuggy, naturally fractured carbonate reservoirs, hydrocarbon is mainly stored in vugs and natural fractures (NFs). To enhance oil production in such reservoirs, matrix acidizing is used to generate wormholes to connect the wellbore with NFs and vugs. Due to the simultaneous existence of NFs and vugs, the acid flow and interaction with rock in acidizing is complicated, and the wormhole propagation behavior needs to be clarified. To this end, the pore structure characterization method accounting for the matrix, vugs, and NFs is established based on geostatistics methods, which is then combined with the two-scale wormhole model to simulate wormhole propagation in the vuggy, naturally fractured carbonate reservoirs. The effects of geological factors and engineering factors on wormholing behavior are analyzed through extensive numerical simulations. The research shows that both the dimensionless correlation length and the areal proportion of vugs affect wormhole propagation. There is an optimal combination of the dimensionless correlation length and the areal proportion (evaluated by comprehensive influence coefficient), rendering more vugs being connected with wormholes. NFs have a dominant effect on wormhole propagation. The optimal natural fracture density and dimensionless length of NFs exist for a given formation with the same vug distribution. The distribution of the NFs and the vugs has a dominant effect on wormhole pattern and vugs that can be connected. In engineering practice, retarded acid system with low diffusion coefficient of hydrogen ions (H+) is recommended to obtain longer wormholes so as to increase the possibility of connecting remote vugs with the wellbore. Meanwhile, for vuggy, naturally fractured carbonate reservoirs, increasing the injection rate promotes acid flow in NFs, facilitating wormhole propagation and connecting with more vugs with the same injection volume as long as the pumping pressure is lower than the formation breaking pressure. This research provides theoretical basis for matrix acidizing in vuggy, naturally fractured carbonate reservoirs.

Prediction of Oil Production in a Tight Sandstone Reservoir: Triassic Chang 9 Member, Jiyuan Area, Ordos Basin, NW China

Tight sandstone oil reservoirs in the Upper Triassic Yanchang Formation of the Ordos Basin are the most promising exploration and development fields owing to their huge production potential. Even though they have received considerable attention in recent years, common productivity prediction methods were not well applied during pre-development owing to their strong internal heterogeneity. In this study, the factors influencing oil production of the Chang 9 Member in the Jiyuan area were investigated and summarized based on drill cores, such as sediment characteristic analysis, lithofacies analysis, other analytical tests, and conventional logging curves. The findings show that fine-sandstone reservoirs with smooth sand body architectures are the main types of tight sandstone commercial oil reservoirs. Furthermore, having high porosity and oil content are prerequisites for commercial oil reservoirs, and the cumulative thickness of effective reservoirs serves as a crucial resource base for them. Through the analysis of logging curves, the relative center of gravity, deviation root of variance, petrophysical index, effective reservoir thickness, and evaluation indicator were used to predict daily oil production, thereby establishing the identification criteria for the ranking of tight sandstone oil reservoirs using logging. Then, the productivity of each reservoir in a single well was predicted by processing the log data from each well using the proposed method, and the productivity prediction results agreed well with the tested results of the perforated interval. This approach highlights the integrated influence of geological factors, physical properties, and the thickness scale of an effective reservoir, thereby improving the predictive capacity of logging curves. Additionally, the proposed methods significantly reduce the need for reservoir parameters better than previous ones, streamline operations, and improve practical applications.

Interactions between Clays and Carbonates in the Aptian Pre-Salt Reservoirs of Santos Basin, Eastern Brazilian Margin

The giant Pre-salt reservoirs represent most of the oil production in Brazil. The main Aptian sag reservoirs were deposited in a unique and highly complex hyper-alkaline lacustrine setting. These deposits are essentially constituted by fascicular and spherulitic calcite precipitated in a magnesian clay matrix (stevensite, kerolite, and saponite/hectorite). Although vital for understanding the origin and main reservoir quality control, the genesis and interactions of clays and carbonates are still poorly constrained. The detailed petrographic description was focused on 812 thin sections from five wells drilled in the Santos Basin Aptian Barra Velha Formation, combined with cathodoluminescence, UV epifluorescence, and X-ray diffraction analyses. The main syngenetic processes were the deposition of finely laminated peloidal and ooidal Mg-clays, the formation of fascicular calcite crusts on the sediment–water interface, and the redeposition of these materials as intraclasts. Abundant clay peloids engulfed in syngenetic shrubs indicate that calcite and clay precipitation was concomitant, though with highly variable rates. Eodiagenetic phases include matrix-replacive and -displacive spherulites and fascicular shrubs; matrix-replacive blocky calcite and dolomite; lamellar carbonates filling matrix shrinkage pores; and microcrystalline calcite, dolomite, and silica replacing the Mg-clay matrix. The preferential dolomitization and calcitization of peloidal layers were most likely due to their higher permeability and larger specific surface. Matrix-replacive saddle dolomite, macrocrystalline calcite, and dawsonite are interpreted as mesodiagenetic or hydrothermal phases after significant matrix dissolution. Unraveling the processes of the formation and alteration of the carbonates and clays and their interactions in the Pre-salt deposits is essential for constraining the depositional and diagenetic conditions in their unique environments and their diagenetic overprinting and for decreasing the exploration risks and increasing the production of those extraordinary reservoirs.