Reservoir Heterogeneity Research Articles

Design of Janus Nanoparticles for Mobility Control in Heterogeneous Reservoirs.

Unfavorable mobility ratios in heterogeneous reservoirs have resulted in progressively poor waterflood sweep efficiency and diminishing production. In order to address this issue, our study has developed amphiphilic-structured nanoparticles aimed at enhancing the microscopic displacement capability and oil displacement efficiency. First, the transport process of Janus nanoparticles in porous media was investigated. During the water flooding, Janus nanoparticle injection, and subsequent water flooding stages, the injection pressure increased in a "stepped" pattern, reaching 0.023, 0.029, and 0.038 MPa, respectively. Second, emulsification effects and emulsion viscosity experiments demonstrated that the amphiphilic structure improved the interaction at the oil-water interface, reducing the seepage resistance of the oil phase through emulsification. In porous media, Janus nanoparticles transported with water exhibit 'self-seeking oil' behavior and interact with the oil phase, reducing the viscosity of the oil phase from 19 to 5 mPa·s at 80 °C. Finally, the core model displacement experiment verified the characteristics of Janus nanoparticles in improving the oil-water mobility ratio. Compared with the water flooding stage, the recovery percent increased by 20.8%, of which 13.7% was attributed to the subsequent water flooding stage. Utilizing the asymmetry of the Janus particle structure can provide an effective path to enhanced oil recovery in inhomogeneous reservoirs.

Numerical modeling of temperature-reporting nanoparticle tracer for fractured geothermal reservoir characterization

Information on the temperature distribution of subsurface reservoirs is essential for geothermal energy development. One of the promising tools to detect the reservoir temperature distribution is temperature-reporting nanoparticle tracers whose functionality has been extensively investigated in both theoretical and experimental ways in the last decade. However, most related studies were limited to simplified geometries and ignored the dynamic interplays of fluid flow, heat transfer, transport and reaction of the temperature-reporting nanoparticle tracer. The response behavior and working mechanisms of such nanotracers in a realistic three-dimensional system still have not been fully revealed through a systematic study. In this work, we develop a numerical modeling approach to simulate field implementation of these nanotracers in a fractured geothermal reservoir. This study aims to evaluate whether the injection of multiple temperature-reporting nanoparticle tracers with different thresholds can be used to estimate the temperature distribution and provide information on the thermal and geological heterogeneities. Several scenarios have been investigated for the geothermal reservoir including homogeneous and non-homogeneous cases (e.g., thermal and geological heterogeneities). Our obtained results from the nanotracer breakthrough curves show that the deviation temperatures in peak concentration values provide an upper limit of the lowest temperature and precise highest temperature for the reservoir temperature range. The deviation temperature of the peak arrival time curve accurately estimates the highest temperature along the main streamlines between the wells. The proposed analysis curves based on the nanotracer breakthrough data were visibly affected by geological heterogeneities including their conductivities and orientations as well as thermal heterogeneities in the geothermal reservoir.

Quantitative facies analysis of a fluvio-aeolian system: Lower Triassic Buntsandstein Group, eastern France

Understanding the factors that control the temporal and spatial evolution of the Lower Triassic Buntsandstein Group, eastern France, is important not just for palaeoenvironmental reconstruction but also because it is an important reservoir for the lithium-rich geothermal brines in the Upper Rhine Graben region. The interval of interest in this study, the Lower Grès Vosgien Formation (LGV), is made up of c. 200 m of clastic deposits of mixed fluvial and aeolian origin. Given the proximity between the outcrops and the areas of mineral and heat exploration, this region offers a unique opportunity for quantitative analysis and correlation between outcrops and reservoirs. The LGV is the thickest Formation in the Buntsandstein Group. However, hitherto, no detailed architectural analysis has been published to reveal the controlling factors of its depositional elements. In this study, high-resolution facies analysis was applied to thirteen outcrops, and a core, to quantify fluvial and aeolian depositional architectures, and to comprehend palaeoenvironmental conditions during their deposition. Two facies associations were identified. The fluvial channel facies association, composed mainly of sandstones deposited in poorly confined, occasionally ephemeral channels, corresponds to 93 % of the total thickness. The analysis of >800 sets of strata characterised by lower-, transitional-, and upper-flow regime sedimentary structures, distributed within different architectural elements, enabled the distinction of temporal and spatial variabilities, and an estimate of fluvial palaeohydraulic characteristics. The wind- and water-laid facies association, which accounts for 7 % of the total thickness, records an architecture controlled by a fluctuating water-table level, and ephemeral floods. Results revealed that aeolian dunes and sand sheets accumulated in distinct temporal moments. The vertical trends, recorded in the core, indicate an upward increase in the frequency of intercalations between the two facies associations, and a decrease in the occurrences of thicker cross-bedded sandstone sets of fluvial origin, which, associated with the overall retrogradational stacking pattern of the LGV, is interpreted as the preserved record of a large distributive fluvial system (DFS). The occurrence of laterally extensive aeolian deposits, overlying fluvial deposits, is often associated by authors with periods of relatively more arid conditions at a regional scale. However, evidence indicates channel belt avulsion as an alternative interpretation for the establishment of the two facies associations. The findings enhance the knowledge about the depositional controlling factors in braided fluvial and aeolian systems, and improve predictive models that account for reservoir heterogeneity in accumulated successions of this type.

Microscopic characteristics of tight sandstone reservoirs and their effects on the imbibition efficiency of fracturing fluids: A case study of the Linxing area, Ordos Basin

The Linxing area within the Ordos Basin exhibits pronounced reservoir heterogeneity and intricate micro-pore structures, rendering it susceptible to water-blocking damage during imbibition extraction. This study delved into the traits of tight sandstone reservoirs in the 8th member of the Shihezi Formation (also referred to as the He 8 Member) in the study area, as well as their effects on fracturing fluid imbibition. Utilizing experimental techniques such as nuclear magnetic resonance (NMR), high-pressure mercury intrusion (HPMI), and gas adsorption, this study elucidated the reservoir characteristics and examined the factors affecting the imbibition through imbibition experiments. The findings reveal that: ① The reservoir, with average porosity of 8.40% and average permeability of 0.642 × 10−3 μm2, consists principally of quartz, feldspar, and lithic fragments, with feldspathic litharenite serving as the primary rock type and illite as the chief clay mineral; ② Nano-scale micro-pores and throats dominate the reservoir, with dissolution pores and intercrystalline pores serving as predominant pore types, exhibiting relatively high pore connectivity; ③ Imbibition efficiency is influenced by petrophysical properties, clay mineral content, and microscopic pore structure. Due to the heterogeneity of the tight sandstone reservoir, microscopic factors have a more significant impact on the imbibition efficiency of fracturing fluids; ④ A comparative analysis shows that average pore size correlates most strongly with imbibition efficiency, followed by petrophysical properties and clay mineral content. In contrast, the pore type has minimal impact. Micropores are vital in the imbibition process, while meso-pores and macro-pores offer primary spaces for imbibition. This study offers theoretical insights and guidance for enhancing the post-fracturing production of tight sandstone reservoirs by examining the effects of these factors on the imbibition efficiency of fracturing fluids in tight sandstones.

Fluid characterization of oil and gas fields: implications for fault and top seal integrity assessment

Integrity of fault and top seal is a key factor that affects hydrocarbon fluid phase distribution in the subsurface. Mapping fluid property distribution can therefore provide important tools towards assessing seal integrity and trapping mechanisms – two of the most critical elements in petroleum systems analysis towards optimzing exploration and development strategies. This is best achieved by proper fluid characterization that integrates fluid geochemistry and pressure–volume–temperature (PVT) data to identify equilibrated and disequilibrated fluid gradients. Fields from Paleozoic and Mesozoic basins in the Arabian Peninsula at different stages of delineation, appraisal, development and management are discussed as examples to demonstrate the role of fluid characterization in aiding the evaluation of top, lateral and fault seal integrity, and in providing insights into the sealing and buffering effects of reservoir heterogeneity on trapping mechanism, fluid distribution and flow capacity. Examples discussed include (1) reservoir heterogeneity controlling fluid distribution and trapping mechanisms in two neighbouring gas fields, (2) geochemical evidence for a lateral seal separating gas condensate region from oil discovered during field development, (3) solid reservoir bitumen atop a giant gas field, (4) selective gas leakage through anhydrite seal, and (5) geochemical evidence for fault-controlled reservoir compartmentalization rather than a hydrodynamically tilted fluid contact in a field at an appraisal stage where PVT data are limited or inconclusive. Put in structural context, seal-related interpretations of the fluid data are aligned with observations from seismic and geological data on the existence of faults with favourable orientations or facies changes. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022

Pore-scale modeling of preformed particle gel (PPG) extrusion in porous media

Preformed particle gel (PPG) is a promising profile control agent for enhanced oil recovery in heterogeneous reservoirs. For an improved sweep, the remigration behavior of PPG once blocked by pore throats is of crucial importance. In this paper, the process of a hyper-elastic particle passing through a pore throat is simulated, allowing investigation of the extrusion mechanism of PPG with deformation under a certain hydraulic pressure. The results reveal that PPG is subjected to a varying resistance during the process of entering, penetrating and leaving the throat. The maximal radial resistance occurs when the particle center arrives at the narrowest throat, whereas the maximal axial resistance occurs before that. In the meantime, it is shown that the particle gel bears over 80% body strain during the extrusion process through frictional pore throat. The hydraulic pressure needed for the PPG extrusion through the pore throat depends on the mechanical behaviors (hyper-elasticity of PPG, and friction coefficient of the PPG-throat interface) and geometrical properties (the particle size, and the shape of throat wall) of the PPG-throat system. Based on the simulation results, an empirical model is finally established to predict the required driving pressure. Eventually, the pore-scale model is upscaled and employed to attain effective pressure windows for profile-control in a reservoir scale formation with 10 times permeability heterogeneity.

Depositional facies controls on reservoir rock typing and heterogeneity: Devonian siliciclastic succession, south central Ghadames basin, Libya

The Devonian sedimentary succession hosts the most potential reservoir targets in Ghadames Basin, Northwest Libya. This succession consists of a complex pattern of siliciclastic facies deposited during successive episodes of sea level fall and rise, thereby leading to a large scale heterogeneity in sandstone facies connectivity and distribution. The present study integrates core sedimentology, wireline logs, and routine and special core analysis to establish a framework for predicting the distribution of the best Devonian reservoir rock types (RRTs). A lowstand amalgamated fluvial sandstone bars only exist in the Lower Devonian Tadrart Formation; the other Devonian rock units consist of transgressive and highstand tidally-influenced estuarine and deltaic facies. The pore system characteristics are controlled by initial depositional attributes where open, megapores with entry displacement pressures <10 psi occur in the quartzose, high energy fluvial sandstone bars, delta distributary channels and mouth bars. These facies are classified as RRTI and are mostly associated with lowstand and late highstand facies. In contrast, the other RRTs display tight pore system with elevated irreducible water content >20%. RRTI rocks account for greater than 90% of the fluid flow capacity in the Devonian reservoirs. A link between the facies depositional setting, RRT distribution, vertical amalgamation and lateral compartmentalization of flow conduits, barriers and baffles zones has been proposed, thereby promoting the predictability of the best reservoir targets.

Simulation of reservoir dynamic damage and influencing factors of horizontal wells in heterogeneous carbonate reservoirs

AbstractAs the development of well types for low permeability reservoirs shifts from vertical to highly inclined/horizontal wells, targeted studies of oil and gas reservoir damage must be conducted for such well types to improve the science and effectiveness of acidification conversion. Taking into account the formation of mud cake and the dynamic damage factors caused by drilling fluid on the reservoir during horizontal well drilling, a refined dynamic description model for nonuniform damage in horizontal wells was established. The coupled simulation accounts for the dynamical destruction of the skin factor of the reservoir and the dynamical generation of the slurry. The coupled model consists of a radial mud cake dynamic formation model, a reservoir damage radius model, a permeability distribution model, and a horizontal well inhomogeneous skin factor model. It captures the dynamic evolution of reservoir damage due to drilling fluid contamination during horizontal well drilling and provides a real‐time representation of changes in the reservoir skin factor of horizontal wells, measuring the depth and extent of radial reservoir damage. Clarifying the extent of reservoir damage and its impact in horizontal well sections can help select appropriate acidification methods, improve acid distribution processes, and ultimately improve the effectiveness of mitigating reservoir damage and increasing oil and gas well productivity.

Characterization of reservoir quality in tight sandstones from the Benxi Formation, eastern Ordos Basin, China

The Benxi Formation in the eastern Ordos Basin harbors abundant natural gas resources and shows promising exploration and development potential. However, the reservoir characteristics are complex, and the primary controlling factors are unclear, presenting significant challenges for reservoir characterization. In response to these challenges, we conducted a systematic study on the characteristics of tight sandstone reservoirs in the Benxi Formation by integrating thin section analysis, scanning electron microscopy, high-pressure mercury injection, and conventional petrophysical analysis alongside well log data analysis. By applying empirical calculation formulas of a porosity evolution quantitative model, we elucidated the primary controlling factors of reservoir heterogeneity. Our research identified that the reservoirs in the eastern Ordos Basin, Benxi Formation, are predominantly composed of quartz sandstone and lithic quartz sandstone, with pore-filling cementation as the dominant cement type and the main storage spaces being intergranular pores and dissolved pores. The homogenization temperatures of fluid inclusions in authigenic quartz range from 92.8 to 185.7°C, indicating that the target layer is in the mesodiagenesis phase B. The main reasons for the differences in reservoir quality in the Benxi Formation are attributed to both sedimentation and diagenesis. In terms of sedimentation, two distinct sedimentary microfacies control the distribution of reservoir quality differences based on variations in quartz content and soluble components. Regarding diagenesis, the Benxi Formation underwent compaction, cementation, and dissolution, with compaction being the fundamental cause of widespread reservoir compaction.

Opportunities and challenges for gas coproduction from coal measure gas reservoirs with coal‐shale‐tight sandstone layers: A review

AbstractThe extraction of coal measure gas has been shifted toward thin gas reservoirs due to the depletion of medium‐thick gas reservoirs. The coproduction of coalbed gas, shale gas, and tight sandstone gas (called a multisuperposed gas system) is a key low‐cost technology for the enhancement of natural gas production from thin gas reservoirs in coal measure. As an emerging engineering exploitation technology at its early stage of development, gas coproduction confronts various engineering challenges in hydraulic fracturing, bottom‐hole pressure regulation, well network arrangement, and extraction sequence. The current understanding of the opportunities and challenges in the gas coproduction from the multisuperposed gas system is not comprehensive enough. In this case, the previous achievements in the field of gas coproduction should be urgently reviewed to provide valuable guidance and recommendations for further development. This review first discusses the regional and spatial distribution characteristics and possible reservoir combinations of gas reservoirs in coal measure. Then, the basic properties of different reservoirs, engineering challenges, and interlayer interference are comparatively analyzed and discussed. The current simulation models for gas coproduction and potential future research directions are further explored. The results indicate that the coupling effects of reservoir heterogeneity, interwell interference, and geological structure for increasing coproduction prediction accuracy should be included in future simulation models for gas coproduction. Careful investigation is required to explore the mechanisms and their further quantifications on the effects of interlayer interference in gas coproduction. The fractal dimension as a scale can play an important role in the characterization of the gas and water transport in different reservoirs. The machine learning methods have tremendous potential to provide accurate and fast predictions for gas coproduction and interlayer interference.

Editorial for the Special Issue “Mineralogical, Geological and Geochemical Heterogeneities of Carbonate Reservoirs”

Carbonate reservoir heterogeneity is a defining characteristic that fundamentally shapes the behavior and properties of subsurface formations [...]

Chemical enhanced oil recovery under Harsh conditions: Investigation of rock permeability and insights from NMR measurements

Injecting surfactant into a hydrocarbon reservoir stands out as a highly effective method for EOR due to its ability to reduce water/oil IFT and alter rock wettability in certain cases. However, the efficiency of this process is compromised in heterogeneous reservoirs, especially carbonates, characterized by significant permeability variations. This study presents findings from three core flooding experiments on heterogeneous carbonate core samples with different permeabilities. The experiments were conducted under representative reservoir conditions of 100 °C, pressures higher than 3000 psi, and seawater salinities and formation water of 57,745 ppm and 213,768 ppm, respectively. In each experiment, seawater was continuously injected followed by continuously injecting a 2500-ppm solution of in-house synthesized Gemini surfactant. Results revealed that the recovery factor was highest in low-permeability rocks and lowest in high-permeability rocks for both seawater and surfactant floods. Surfactant floods yielded additional recoveries of 31%, 23%, and 19% for low, medium, and high-permeability samples, respectively. Nuclear magnetic resonance (NMR) analysis on short analogous core plugs at different flooding stages confirmed these results. Effluent analysis on the produced aqueous phase indicated that dynamic retention was highest (0.467 mg/gm-rock) in the lowest permeability and lowest (0.146 mg/gm-rock) in the highest permeability rock. NMR analysis suggested that the surfactant's recovery performance and dynamic retention were influenced by the larger surface area of low-permeability rocks, facilitating increased contact with the surfactant. Utilizing NMR monitoring in this work enhances EOR insights through integrated studies and coreflooding experiments and establishes a novel framework for complex reservoir conditions.

Pressure transient behavior of multiwell interference in strip-shaped heterogeneous reservoirs

Fault-karst reservoirs are commonly observed as strip-shaped characteristic. Due to the strong heterogeneity of fault-karst reservoir, the production well is often affected by the simultaneous interference from multiple wells. However, multiwell interference well testing without shut-in becomes popular for the purpose of continuous production, there are few related models that are able to analyze fault-karst reservoirs. This paper derives a novel multiwell interference analytical model based on Darcy flow in the strip-shaped heterogeneous reservoir. The accuracy of this bottom-hole pressure (BHP) solution is verified by comparing with numerical simulation results. Then the effect of interference’s distance and intensity on BHP are investigated. The results show that pressure and its derivative curves can diagnose the interference flow regimes. The timing of interference occurrence is determined by the formation transmissibility, storability and well distance. Also, the characteristic of the type curve is related with the production of interfering wells. This work provides technical support for accurately capturing interference effect and gives a comprehensive workflow for rapidly diagnosing the multi-well interference by analyzing BHP data.

Building initial model for seismic inversion based on semi‐supervised learning

AbstractSeismic inversion is an important tool for reservoir characterization. The inversion results are significantly impacted by a reliable initial model. Conventional well interpolation methods are not able to meet the needs of seismic inversion for lateral heterogeneous reservoirs. Inspired by the sequence modelling network and seismic inversion in the Laplace–Fourier domain, we propose an initial model‐building method using semi‐supervised learning strategy. The proposed method considers spatial information to ensure the horizontal continuity of the initial model. Based on the fact that the low‐frequency components of seismic signals in the Laplace–Fourier domain are easier to obtain, we use the forward model in the Laplace–Fourier domain to replace the time‐domain forward model. The proposed workflow was validated using the Marmousi II model. Although the training was carried out on a small number of low‐frequency impedance traces, the proposed workflow was able to build low‐frequency model for the entire Marmousi II model with a correlation of 98%. Field data examples demonstrate the feasibility and effectiveness of the proposed method. For lateral heterogeneous reservoirs, the proposed method performs better than the well interpolation method. By utilizing the model obtained by the proposed method as the initial low‐frequency model of the conventional inversion method, it is possible to estimate better inversion results. The results of different combinations of training sets demonstrate the stability of the proposed method. This method may still be a viable choice if there is lateral heterogeneity underground but not much well‐logging label data.

Three-Dimensional Heterogeneity of the Pore and Fracture Development and Acoustic Emission Response Characteristics of Coal Rocks in the Yunnan Laochang Block

Studying the heterogeneity of coal reservoirs is significant to coal bed methane (CBM) exploitation. To investigate the development of the pore–fracture and acoustic emission response characteristics of the coal rock in the Yunnan Laochang block, four cores were extracted from the same coal rock in different directions. Through a comprehensive analysis using CT scanning and three-axis compression tests combined with synchronous acoustic emission experiments, a three-dimensional visualization of the pore–fracture structure and an analysis of the acoustic emission process during the elastic phase were conducted. Additionally, the impact of the heterogeneous development of pore–fractures on the acoustic emission characteristics was discussed. The results show that: there is strong heterogeneity in pore and fracture development within the coal rock, with the most significant development occurring along the direction of vertical stratification; the acoustic emission process in the elastic phase can be divided into three stages: strong–weak–strong; the development of pores and fractures affects the acoustic emission characteristics, with both counts and signal strength increasing as the percentage of voids rises; and the inferred in situ stress aligns with strike-slip faulting stress using acoustic emission. These results can provide a reference for the actual project.

METHOD FOR FORECASTING INCREASE IN LIQUID PRODUCTION FOR OPTIMIZE SELECTION OF CANDIDATES FOR HYDRAULIC FRACTURING

Over the past 20 years, the structure of reserves of Russian oil fields has undergone significant changes: with a general increase in reserves, there has been a significant increase in the share of hard to recover reserves (HTR). In the HTR structure of the Russian Federation, low-permeability and heterogeneous reservoirs are identified as the main subgroup (64 %), in 2022, approximately 30 % of all Russian oil was produced from HTR (166 from 535 million tons). In such reservoirs, to maintain and ensure high levels of oil recovery, a workovers such as hydraulic fracturing (HF) is used.Petroleum production companies have various technical and infrastructal capabilities for the selection of candidate wells for workover. Some oil companies use the support of design institutes and service companies that mining andhave specialized geological software products for monitoring and selection of workovers, others make do with the knowledge and skills of selecting their own specialists. However, due to the development of residual recoverable reserves and the unprofitability of the workover every year to select candidate wells, it is becoming increasingly difficult to select candidate wells. Working out the entire well stock and selection candidate wells using standard techniques takes a huge amount of time for a specialist. The article proposes a solution to the topical issue of optimizing the selection of candidate wells for hydraulic fracturing by predicting the dynamics of production wells based on historical data for various geological conditions. The developed method for forecasting the flow rate of liquid and oil on the basis of the rate of change in reservoir pressure and water cut of the well allows you to predict the flow rate for two years ahead, monthly estimates the possible increase from hydraulic fracturing and allows you to determine the optimal time for repeated or primary hydraulic fracturing at the well. This approach sharply narrows the number of potential candidates from a coupe of hundred to two to three dozen potential candidates.

Permeability Prediction Using Advanced Magnetic Resonance Tools and Hydraulic Reservoir Units Techniques for the Pliocene Sand Reservoirs, Sapphire Offshore Gas Field, Mediterranean, Egypt

Permeability derived from magnetic resonance advanced logging tools was used to unlock the Pliocene sandstone reservoir heterogeneity. Permeability prediction from well logs is a significant target due to the unavailability of core data. The hydraulic flow unit approach is used to classify the reservoir rocks according to their porosity-permeability relationship. The predicted permeability is calculated using Sapphire-Dh magnetic resonance porosity and permeability relationship for each flow unit. Flow Zone Indicator and the quality flow unit have a direct proportion relationship. For the model's verification, the predicted permeability is plotted against the measured resonance permeability in Sapphire-Dh as a reference studied well, showing highly matching results. Accordingly, the applied approach is implemented in the other three wells, which have neither core samples nor advanced logs measurements.

Insights into Molecular Dynamics and Oil Extraction Behavior of the Polymeric Surfactant in a Multilayered Heterogeneous Reservoir.

Interlayer heterogeneity, an inevitable and complex challenge during water flooding, seriously constrains the spread of the sweep region and oil recovery enhancement in multilayered heterogeneous reservoirs. To overcome this challenge, a novel polymeric surfactant, having an excellent performance in the reduction of interfacial tension (IFT) and the increase of viscosity of displacing fluid, is applied for enlarging the sweep resonance and increasing the oil washing efficiency. Through the molecular dynamics (MD) simulation, the molecular distributing mechanisms of the polymeric surfactant at the oil-water interface are analyzed to provide the theoretical basis for explaining the microscopic mechanism of oil extraction. To directly reflect the microscopic behavior of oil extraction, multiple transparent sand-packed models are designed to investigate the flowing behavior of different fluids and the extracted mechanisms of the remaining oil in both pore and macroscales. The multilayered heterogeneous reservoirs consisting of high-, moderate-, and low-permeability layers are fabricated to represent a heterogeneous characteristic. The recognition from the visual experiment and MD simulation can study the performance control, the extracting performance of the remaining oil, and the expression of the displacing front from different perspectives. The results from MD simulation demonstrate that the polymeric surfactant can promote the disintegration of the remaining oil and enhance its mobility. The experimental results indicate that the sweep efficiency is restricted by viscous fingering and tongue advance. Through the analysis of mathematical models, the rising mobility ratio and the location of the displacing front have a strong positive relationship with viscous fingering and tongue advance, which can reasonably explain the plugging performance of the polymeric surfactant, greatly improving the sweeping effect of the whole reservoir. Moreover, the Marangoni effect generated by the IFT gradient can induce the transformation of interfacial energy to displacement kinetic energy by the emulsification of the oil-water interface so that the remaining oil in the blind-end pore can be effectively extracted. However, by comparing data from image quantification techniques and production dynamic performance, the sweep efficiency (484%) was significantly greater than that of oil recovery (300%), demonstrating that the expanded sweep effect still plays a dominant role in the extraction of remaining oil after polymeric surfactant flooding. This study provides a novel plugging and effective washing agent that is expected to be an excellent and comprehensive method for solving the problem of low oil recovery in multilayered heterogeneous reservoirs.

Diagenetic controls over reservoir quality of tight sandstone in the lower Jurassic reservoir in the Lenghu area, the north margin of Qaidam basin

The Lower Jurassic Reservoir (LJR) in the Lenghu area on the northern margin of the Qaidam Basin (NMoQB) has become the most promising target for hydrocarbon exploration. The reservoir has experienced complex diagenesis; however, the porosity evolution and the influence of different diagenesis events on reservoir densification remains unclear. In this study, various analytical methods was first used to clarify the diagenetic stage and sequence, establish a porosity evolution model, quantitatively analyze the time and influence of different diagenesis events on reservoir densification, and illustrate the densification mechanism of tight sandstone reservoir in the Lenghu area. The results showed that the dominant rock types in the LJR were feldspathic litharenite, followed by litharenite, lithic arkose, and a small amount of subarkose and sublitharenite. The reservoir is a typical tight sandstone reservoir (TSR), with average porosity and permeability of 5.5% and 0.08 mD, respectively. The pore types were primarily secondary pores, followed by residual intergranular pores and occasional fractures. Diagenesis of LJR has entered the meso-diagenetic stage A, with minor progression into meso-diagenetic stage B. Quantitative calculation showed that the initial porosity of LJR is 32.2%. In eo-diagenetic stage A, compaction is the main factor for porosity reduction. In eo-diagenetic stage B, the porosity loss rates caused by compaction and cementation were 81.5% and 11.8%, respectively. In this stage, the LJR in the Lenghu area has almost been densified, mainly affected by compaction, calcite cementation and clay minerals cementation. Additionally, cementation is an important factor causing reservoir heterogeneity and is dominated by calcite and clay mineral cementation. After entering the meso-diagenetic stage A, dissolution is the main diagenesis event, which can increase porosity by 6.0%. This stage is the critical period for forming high-quality reservoir of LJR in the Lenghu area, mainly in the 4,400 m depth. In meso-diagenetic stage B, the influence of dissolution gradually decreased. Simultaneously, in this stage, the cementation of iron-bearing calcite further strengthened the densification of the LJR in the Lenghu area.

Integration of electromagnetic, resistivity-based and production logging data for validating lithofacies and permeability predictive models with tree ensemble algorithms in heterogeneous carbonate reservoirs

This study develops an innovative workflow to identify discrete lithofacies distributions with respect to the well-log records exploiting two tree-based ensemble learning algorithms: extreme gradient boosting (XGBoost) and adaptive boosting (AdaBoost). In the next step, the predicted discrete lithofacies distribution is further assessed with well-log data using an XGBoost regression to predict reservoir permeability. The input well-logging records are gamma ray, neutron porosity, bulk density, compressional slowness, and deep and shallow resistivity. These data originate from a carbonate reservoir in the Mishrif Basin of southern Iraq's oilfield. To achieve a solid prediction of lithofacies permeability, random subsampling cross-validation was applied to the original dataset to formulate two subsets: training for model tuning and testing for the prediction of subsets that are not observed during the model training. The values for the total correct percentage (TCP) of lithofacies predictions for the entire dataset and testing subset were 98 and 93% using the XGBoost algorithm, and 97 and 89% using the AdaBoost classifier, respectively. The XGBoost predictive models led in attaining the least uncertain lithofacies and permeability records for the cored data. For further validation, the predicted lithofacies and reservoir permeability were then compared with porosity–permeability values derived from the nuclear magnetic resonance (NMR) log, the secondary porosity of the full-bore micro imager (FMI) and the production contribution from the production–logging tool (PLT). Therefore, it is believed that the XGBoost model is capable of making accurate predictions of lithofacies and permeability for the same well's non-cored intervals and other non-cored wells in the investigated reservoir.