Conglomerate Reservoir Research Articles

Supervised deep learning-based paradigm to screen the enhanced oil recovery scenarios

High oil prices and concern about limited oil reserves lead to increase interest in enhanced oil recovery (EOR). Selecting the most efficient development plan is of high interest to optimize economic cost. Hence, the main objective of this study is to construct a novel deep-learning classifier to select the best EOR method based on the reservoir’s rock and fluid properties (depth, porosity, permeability, gravity, viscosity), and temperature. Our deep learning-based classifier consists of a one-dimensional (1D) convolutional neural network, long short-term memory (LSTM), and densely connected neural network layers. The genetic algorithm has been applied to tune the hyperparameters of this hybrid classifier. The proposed classifier is developed and tested using 735 EOR projects on sandstone, unconsolidated sandstone, carbonate, and conglomerate reservoirs in more than 17 countries. Both the numerical and graphical investigations approve that the structure-tuned deep learning classifier is a reliable tool to screen the EOR scenarios and select the best one. The designed model correctly classifies training, validation, and testing examples with an accuracy of 96.82%, 84.31%, and 82.61%, respectively. It means that only 30 out of 735 available EOR projects are incorrectly identified by the proposed deep learning classifier. The model also demonstrates a small categorical cross-entropy of 0.1548 for the classification of the involved enhanced oil recovery techniques. Such a powerful classifier is required to select the most suitable EOR candidate for a given oil reservoir with limited field information.

Heterogeneity of a Sandy Conglomerate Reservoir in Qie12 Block, Qaidam Basin, Northwest China and Its Influence on Remaining Oil Distribution

In view of the key geological factors restricting reservoir development, the reservoir heterogeneity of an alluvial fan sandy conglomerate reservoir in the Qie12 block of Qaidam Basin, Northwest China, and its influence on remaining oil distribution, were studied according to geology, wireline logging data, and dynamic production data. This study illustrates that the difference in pore structures, which are controlled by different sedimentary fabrics, is the main cause of reservoir microscopic heterogeneity. Besides, the temporal and spatial distribution of architectural units in the alluvial fan controls reservoir macroheterogeneity. Our results show that the thick sandy conglomerate develops two types of pores, two types of permeability rhythms, two types of interlayers, two types of interlayer distribution, two types of effective sand body architecture, and four types of sand body connecting schemes. The strongest plane heterogeneity is found in the composite channel unit formed by overlapping and separated stable channels of the middle fan, and the unit’s permeability variation coefficient is >0.7. However, the variation coefficient in the range of 0.3–0.5 is found in the extensively connected body unit sandwiched with intermittent channels of the inner fan. The distributions of the remaining oil vary significantly in different architectural units because of the influence of reservoir heterogeneity, including distribution patterns of flow barriers, permeability rhythm, and reservoir pore structures. The composite channel unit formed by overlapping and separated stable channels, or the lateral alternated unit with braided channel and sheet flow sediment of the middle fan, is influenced by the inhomogeneous breakthrough of injection water flowing along the dominant channel in a high-permeability layer. The microscopic surrounding flow and island-shaped remaining oils form and concentrate mainly in the upper part of a compound rhythmic layer. Meanwhile, in the extensively connected body unit sandwiched with intermittent channels of the inner fan, poor injector–producer connectivity and low reservoir permeability lead to a flake-like enrichment of the remaining oil.

Study on Compatibility between Complex Mode Micropore Structure and Polymer Solution of Different Formulation for Conglomerate Reservoir

In this paper, the conglomerate reservoir is selected as the object to investigate the micropore structure and the compatibility of polymer solutions. Firstly, the characteristics of complex mode pore structure are analyzed based on casting thin sections, scanning electron microscope, and capillary pressure curve. Then the conglomerate reservoir is divided into five types by use of the K-means clustering algorithm, and the differences in micropore structure among the different reservoir types are also clarified. Secondly, the dynamic light scattering technology is used to directly determine the hydrodynamic diameter of different polymer formulations. As the polymer molecular weight increases, the average hydrodynamic diameter becomes larger, and with the same polymer molecular weight, the average hydrodynamic diameter becomes gradually larger as the solution concentration increases. Based on the above research results, the matching relationship between five reservoir types and polymer solutions is determined through laboratory experiments. The experimental results show that when the polymer molecular weight is determined, the volume of pore volume that can be effectively swept by polymer hydration molecules gradually decreases as the concentration of the solution increases. When the polymer molecular weight and its concentration are both determined, the pore volume of effective displacement of polymer-hydrated molecules also gradually reduces with becoming worse reservoir pore structure. The scope of application of different polymer formulations becomes progressively smaller as the microscopic pore structure of type I to type V reservoirs becomes deteriorated. The compatibility between the micropore structure of different conglomerate reservoir types and polymer solution is determined to provide the geological basis for the reasonable formulation of the polymer flooding scheme.

Case Study on the Effect of Acidizing on the Rock Properties of the Mahu Conglomerate Reservoir

The development of the Mahu tight reservoir has adopted horizontal wells with staged fracturing. In the fracturing, there is a problem of a high fracturing pressure. Acid treatment is often used to lower the fracturing pressure on site. At present, the impact of this acid treatment on the physical parameters of the rocks of the reservoir in the Mahu region has not been systematically studied. Aiming to solve this problem, this paper conducted an experimental study on how acid dissolution affects the physical properties of the Mahu conglomerate, including its porosity, permeability, triaxial rock mechanical parameters, tensile strength, and mineral composition. First, the experimental scheme was designed. Next, a series of experiments were conducted. Finally, the experiment results were analyzed comparatively before and after acidizing. The acid composition, concentration, and contact time were the main factors for the analysis, based on which the acid system and related parameters were recommended. This study showed that the Mahu conglomerate exhibited brittle plasticity characteristics under stress. The carbonate content in this region was low, while the feldspar content was high, so it was necessary to use mud acid to effectively dissolve feldspar, clay, and other silicates. After acidizing, the porosity was 200% of the original value. The permeability increased by up to 14 times. The tensile strength decreased significantly by up to 84%. The value of Young’s modulus of the rock decreased by up to 63.6%. The value of Poisson’s ratio was reduced by up to 40.7%. A combination of 6% HF + 15% HCl is recommended, with an effective acid treatment time of over 60 min for the Mahu conglomerate. Acidizing could significantly change the mechanical properties and permeability of the rock of the Mahu conglomerate reservoir, thus effectively reducing the formation fracturing pressure. This research provides technical support for Mahu acid dipping in horizontal well fracturing.

Study the Elastic Parameters of Sandy Conglomerate under Different Burial History and Petrophysical Modeling

Over the past few years, significant exploration breakthroughs have been made in the sandy conglomerates reservoir of the Triassic Baikouquan Formation in the Mahu Sag, Junggar Basin, China. However, the elasticity and pore characteristics of the tight sandy conglomerates reservoir in this area are still unclear. Through a systematic sonic testing program of the sandy conglomerates sample collected from the Mahu Sag, the regularity behind the variation of the elasticity and pore characteristics of the sample has been analyzed and captured. The Triassic Baikouquan Formation of the slope of Mahu Sag has been through complex burial and diagenetic history. The compaction, cementation, and dissolution are the three types of diagenesis that have the greatest impact on pore characteristics in the study area. In order to quantitatively describe the influence of this complex burial and diagenetic history, we present a rock-physics modeling approach to describe the elastic properties of sandy conglomerate sample. The overall strategy of the modeling is to combine the contact cement theory (CCT), differential effective medium (DEM) and the upper Hashin-Shtrikman bound. The CCT model can well describe the history of cementation, DEM model is suitable for the history of dissolution, and HS upper bound is used to describe the history of compaction. Then, the model is used to describe well log data from sandy conglomerates reservoirs in Mahu Sag and successfully explain the rock porosity, pore shape trends, and the elasticity in the sandy conglomerate reservoirs.

Similarity-based laboratory study of CO2 huff-n-puff in tight conglomerate cores

Tight conglomerate reservoirs are featured with extremely low permeability, strong heterogeneity and poor water injectivity. CO2 huff-n-puff has been considered a promising candidate to enhance oil recovery in tight reservoirs, owing to its advantages in reducing oil viscosity, improving mobility ratio, quickly replenishing formation pressure, and potentially achieving a miscible state. However, reliable in-house laboratory evaluation of CO2 huff-n-puff in natural conglomerate cores is challenging due to the inherent high formation pressure. In this study, we put forward an equivalent method based on the similarity of the miscibility index and Grashof number to acquire a lab-controllable pressure that features the flow characteristics of CO2 injection in a tight conglomerate reservoir. The impacts of depletion degree, pore volume injection of CO2 and soaking time on ultimate oil recovery in tight cores from the Mahu conglomerate reservoir were successfully tested at an equivalent pressure. Our results showed that oil recovery decreased with increased depletion degree while exhibiting a non-monotonic tendency (first increased and then decreased) with increased CO2 injection volume and soaking time. The lower oil recoveries under excess CO2 injection and soaking time were attributed to limited CO2 dissolution and asphaltene precipitation. This work guides secure and reliable laboratory design of CO2 huff-n-puff in tight reservoirs with high formation pressure.

The characteristics and genetic mechanisms of the Upper Permian Shangwuerhe clastic reservoir in the eastern Junggar Basin, Northwest China

In this paper, the lithology, pore type, throat structure, and physical characteristics of the sandstone and conglomerate reservoirs of the Upper Permian Shangwuerhe Formation in the Fukang Sag of the Junggar Basin were analyzed through rock cast thin section, scanning electron microscopy, fluid inclusions, piezometric mercury, and porosity–permeability analysis. In addition, the reservoir densification mechanism and the genesis of deep effective reservoirs were discussed. The results show that the reservoir is dominated by lithic sandstone (or lithic sandstone conglomerate). The lithic fragments primarily comprise tuffaceous volcanic rocks, supported by grains and cemented by clay, carbonate, authigenic quartz, and laumontite. The reservoir properties are characterized by extra-low porosity and permeability, and the pore type is dominated by inter- and intragrain dissolved pores of lithic fragments, feldspar, and quartz. The pore connectivity is poor due to poorly sorted extra-fine throat channels. The tightness of the reservoir.is due to the strong cementation of calcite, chlorite, montmorillonite, illite-montmorillonite mixed layer, authigenic quartz, and laumontite. Furthermore, the large amount of Ca2+ released by the hydration of tuff rock debris and intermediate–basic volcanic rock debris and the CO2-rich thermal fluid from the deep layers cause the development of several calcites. The formation of several montmorillonites is mainly related to the alteration of filled volcanic ash, and the hydration of volcanic tuff material primarily causes the development of laumontite cementation. The dissolution of feldspar and various volcanic lithic fragments by acidic fluids triggers the physical improvement of the reservoir in the local section.

Hydraulic fracture development in conglomerate reservoirs simulated using combined finite-discrete element method

Hydraulic fracturing is known to be the most effective stimulation to enhance fractured reservoir permeability by creating hydraulic fractures (HFs). The efficiency of a HF fluid injection largely depends on the pre-existing discontinuities or sources of heterogeneities. These features need to be considered in a HF operation design. Amongst these features, conglomerate reservoirs containing blocks in a matrix are largely ignored despite their presence in deep rocks. This study focuses on the HF development in such grounds and simulates their hydro-mechanical behaviour by using the combined finite-discrete element method (FDEM), which is fully capable of modelling HF propagation in heterogeneous rocks. First, the capabilities of the FDEM are verified against existing analytical solutions and experimental fluid injection and then employed to model HF development. In the conglomerate models, three blocks with low to high strength properties are simulated to assess the effect of block strength on the HF development pattern. Various controlling parameters, including in-situ stresses, flow rate, fluid kinematic viscosity, directional HF (DHF), properties of the interface between the blocks and matrix, and their effects on the HF path are investigated. The results show a significant influence of blocks in a matrix on the HF pattern. The HF interaction with the blocks of different shapes and dimensions is shown to be complex, and six interaction types for the blocks are identified based on the close observation of the results. It is also found that to achieve a successful HF injection in such grounds, a low flow rate with a low viscous fluid can be a good strategy. Also, it is shown that the blocks' strength significantly affects the type of failure (tensile or shear) and the breakdown pressure.

Study on factors affecting the petro physical properties of sandstone and conglomerate reservoirs of Baikouquan Formation, Junggar Basin

In recent years, oil and gas exploration of the Baikouquan Formation in the northwestern margin of the Junggar Basin has seen major breakthroughs have been made in oil and gas exploration. Sandstone and conglomerate reservoirs are developed in the Baikouquan Formation in this area, but the factors affecting the differences in petro physical properties of these two types of reservoirs are still unclear. In this paper, taking the Baikouquan Formation in the Hongcheguai area on the northwestern margin of the Junggar Basin as an example, a large number of core observations, thin sections, scanning electron microscopy, and petro physical property test data were used to evaluate the petro logical characteristics, reservoir space types, digenesis and pore evolution of the sandstone and conglomerate reservoirs. The results show that the sandstone and conglomerate rocks of the Baikouquan Formation in the study area have a large content of tuffaceous components. The sandstone reservoirs are dominated by primary intergranular pores, and the conglomerate reservoirs are dominated by secondary dissolved pores. In addition, the porosity is negatively correlated with rock permeability for the conglomerate rocks of the Baikouquan Formation. However, the porosity is positively correlated with rock permeability of the sandstone reservoirs. According to the analysis of the digenetic process, the compaction and cementation can lead to a significant decrease in the petro physical properties of the reservoir. While dissolution can improve the petro physical properties of the sandstone reservoirs to a small extent, and can improve that of the conglomerate reservoirs to a greater extent. Moreover, local fractures are important factors affecting the petro physical properties of the conglomerate reservoirs. The existence of abnormal high pressure has a certain effect on the preservation of primary pores. On the whole, the controlling factors of the petro physical properties of the conglomerate reservoirs in the Baikouquan Formation include sedimentation, diagenesis, and tectonic actives, while that of the sandstone reservoirs mainly include sedimentation and diagenesis.

A novel machine learning framework for efficient calibration of complex DEM model: A case study of a conglomerate sample

The conglomerate reservoirs in the Mahu Sag of the Junggar Basin, northeastern China are featured high heterogeneity and complicated lithology. The reservoirs have experienced a decent production with the application of horizontal well drilling and multistage fracturing. However, the mechanical behavior of the conglomerate formation remains poorly understood. In this respect, the discrete element method (DEM) can be used to efficiently investigate the mechanical behavior of geomaterials with complex lithologies. The implementation of DEM requires a precise set of microscopic parameters, for which the conventional trial-and-error methods are time-consuming. In this regard, an end-to-end machine learning (ML) framework was proposed to achieve an efficient calibration of the complex DEM model. The framework contains two stages, with one predicting the strength of a single phase geomaterial and the other forecasting the overall strength of a complex geomaterial sample containing multiple phases. Different ML models were attempted to evaluate their performances. The results demonstrate that the random forest (RF) model performs with high accuracy at the first stage, and the support vector machine (SVM) model outperforms other ML models in terms of accuracy and convergence at the second stage. From deploying the ML framework, a fast and accurate calibration approach of conglomerate DEM models was proposed and explored in the case study. Moreover, the sensitivity analysis examined the contribution of each parameter to the overall mechanical behavior and provides the suggested values of microscopic parameters. The validity of the application of the training models on the synthesized data was analyzed to address the data shortage issue. In summary, the ML framework not only enables users to fast and accurately calibrate the microscopic parameters of the complex DEM model, but also effectively assesses the contribution of microscopic parameters to help understand their effects on the overall mechanical behavior.

Study on Microscopic Pore Structure Classification for EOR of Low Permeability Conglomerate Reservoirs in Mahu Sag

The microscopic pore structure controls the fluid seepage characteristics, which in turn affect the final recovery of the reservoir. The pore structures of different reservoirs vary greatly; therefore, the scientific classification of microscopic pore structures is the prerequisite for enhancing the overall oil recovery. For the low permeability conglomerate reservoir in Mahu Sag, due to the differences in the sedimentary environment and late diagenesis, various reservoir types have developed in different regions, so it is very difficult to develop the reservoir using an integrated method. To effectively solve the problem of microscopic pore structure classification, the low permeability conglomerate of the Baikouquan Formation in Well Block Ma18, Well Block Ma131, and Well Block Aihu2 are selected as the research objects. The CTS, HPMI, CMI, NMR, and digital cores are used to systematically analyze the reservoir micro pore structure characteristics, identify the differences between different reservoir types, and optimize the corresponding micro pore structure characteristic parameters for reservoir classification. The results show that the pore types of the low permeability conglomerate reservoir in the Baikouquan Formation of the Mahu Sag are mainly intragranular dissolved pores and residual intergranular pores, accounting for 93.54%, microfractures and shrinkage pores that are locally developed, accounting for 5.63%, and other pore types that are less developed, accounting for only 0.83%. On the basis of clear pore types, the conglomerate reservoir of the Baikouquan Formation is divided into four types based on the physical properties and microscopic pore structure parameters. Different reservoir types have good matching relationships with lithologies. Sandy-grain-supported conglomerate, gravelly coarse sandstone, sandy-gravelly matrix-supported conglomerate, and argillaceous-supported conglomerate correspond to type I, II, III, and IV reservoirs, respectively. From type I to type IV, the corresponding microscopic pore structure parameters show regular change characteristics, among which, porosity and permeability gradually decrease, displacement pressure and median pressure increase, maximum pore throat radius, median radius, and average capillary radius decrease, and pore structure becomes worse overall. Apparently, determining the reservoir type, clarifying its fluid migration rule, and formulating a reasonable development plan can substantially enhance the oil recovery rate of low permeability conglomerate reservoirs.

Quantitative Study of Diagenesis and Dissolution Porosity in Conglomerate Reservoirs

Quantitative Study of Diagenesis and Dissolution Porosity in Conglomerate Reservoirs

Classification and Assessment of Core Fractures in a Post-Fracturing Conglomerate Reservoir Using the AHP–FCE Method

To characterize the hydraulic fracture network of a conglomerate reservoir, a slant core well was drilled aimed to obtain direct information regarding hydraulic fractures through slant core at the conglomerate hydraulic fracturing test site (CHFTS). Core fracture classification was the fundamental issue of the project. In this study, three grade classifications for core fractures were proposed. Comprehensive classification of core fractures was carried out using the analytic hierarchy process (AHP)–fuzzy comprehensive evaluation (FCE) method. Finally, the fracture classification results were validated against numerical simulation. The grade-1 fracture classification included hydraulic fractures, drilling-induced fractures and core cutting-induced fractures. A total of 214 hydraulic fractures were observed. For the grade-2 classification, the hydraulic fractures were divided into 47 tensile fractures and 167 shear fractures. For the grade-3 classification, the shear fractures were subdivided into 45 tensile-shear fractures and 122 compression-shear fractures. Based on the numerical verification of the core fracture classifications, the dataset acquired was applied to analyze the spatial distribution of tensile and shear fractures. Results showed that the tensile fractures were mainly in the near-wellbore area with lateral distances of less than 20–25 m from the wellbore. The shear fractures were mainly in the far-wellbore area with lateral distances of 20–30 m from the wellbore. These results provide a basis for understanding the fracture types, density, and failure mechanisms of post-fracturing conglomerate reservoir.

Research on Mechanical Properties and Failure Mode of Conglomerate Based on Discrete Element Method

Conglomerate reservoir is an important part of unconventional oil and gas resources, which has great developmental potential. However, its sedimentary environment and structural background are complex, and its cementation types, gravel volume fraction and shape are quite different, which leads to its strong heterogeneity. When developing a conglomerate reservoir, it is extremely difficult to drill because of its strong heterogeneity. It is difficult to obtain the mechanical properties and laws of the conglomerate through physical experiments, which further restricts the development process of conglomerate reservoirs. In order to study its failure law, a three-dimensional numerical model of a conglomerate is built based on the discrete element method, and the effects of cementation strength and gravel characteristics on the mechanical properties of the conglomerate are emphatically studied. The results show that the elastic modulus and uniaxial compressive strength of the conglomerate decrease obviously with the decrease in cementation strength. With the increase in cementation strength, the normal contact force of the conglomerate model increases significantly, the distribution of normal contact force changes from cylinder to sphere, and the heterogeneity of the conglomerate decreases. There is a threshold value for the influence of cementation strength on mechanical properties of the conglomerate, and when the threshold is exceeded, the mechanical properties of the conglomerate no longer change obviously. With the increase in gravel content, the uniaxial compressive strength of the conglomerate decreases at first and then increases, the phenomenon of penetrating gravels and bypassing gravels increases, and the single diagonal crack changes into diagonal cross cracks; the cementation strength and gravel content of gravel jointly affect the mechanical properties and fracture morphology of the conglomerate, and its stress–strain relationship is the external macroscopic expression of normal contact force of internal particles.

Impact of sedimentation and diagenesis on deeply buried sandy conglomerate reservoirs quality in nearshore sublacustrine fan: A case study of lower Member of the Eocene Shahejie Formation in Dongying Sag, Bohai Bay Basin (East China)

The sandy conglomerates of the lower member of Shahejie (Es4x) in the north of Dongying Sag, Bohai Bay Basin, were investigated to understand the formation mechanism of the good reservoir and controlling factors in deeply buried strata. This research is based on seismic, logging, and core data and comprehensively utilizes methods such as core description, petrographic analysis, cathodoluminescence image analysis, SEM-EDS analysis, and mercury intrusion. The sandy conglomerates are predominantly lithic arkose and litharenite. The reservoirs in the Es4x have experienced three diagenetic processes, compaction, dissolution, and cementation. Compaction remains the major factor affecting the reservoir quality, mainly in the progradation sequence, and cementation has a destructive effect on reservoirs, principally in the retrogradation sequence. The quantification of the compaction by the compaction index revealed that mechanical compaction is higher in the progradation sequence (0.68) than in the retrogradation sequences (0.59). Compaction is suppressed by carbonate cementation, but the extensive cementation significantly degrades the reservoir quality, especially in the retrogradation sequence. Dissolution of different rock fragments, feldspar, and the whole dissolution, in general, enhance the reservoir's quality in both intervals but more in the progradation sequence. Three types of reservoirs representing type I, type II, and Type III mercury intrusion capillary pressure curves were encountered in the Es4x. The braided channels in the progradation and retrogradation sets encompass the greatest reservoir quality and are characterized by type I and II reservoirs with good petrophysical properties. The preeminent reservoirs appear in the braided channels of the progradation set. The development of high-quality reservoirs is governed by the depositional subfacies, compaction, and dissolution in the Es4x. This study will contribute to comprehending the origin of the genesis mechanism of high-quality in deep sublacustrine sandy conglomerate and will help the exploration and pre-drill for favorable reservoirs in similar basins around the world.

Effects of Clay Mineral Content and Types on Pore-Throat Structure and Interface Properties of the Conglomerate Reservoir: A Case Study of Baikouquan Formation in the Junggar Basin

Many factors need to be considered in the evaluation of tight conglomerate reservoirs, including the microscopic pore-throat structure, pore connectivity, lithology, porosity, permeability, and clay mineral content. The contents and types of clay minerals reflect the mineral evolution process during the deposition of the reservoir and can reflect the reservoir’s physical properties to a certain extent. In this study, cores from the Baikouquan Formation in Mahu were used to comprehensively analyze the effects of the clay mineral content on the physical properties of a tight conglomerate reservoir, including field emission scanning electron microscopy (FE-SEM), casting thin section observations, X-ray diffraction (XRD), interface property testing, high-pressure mercury injection, low temperature N2 adsorption, and nuclear magnetic resonance (NMR)-movable fluid saturation testing. The results revealed that differences in different lithologies lead to differences in clay mineral content and pore structure, which in turn lead to differences in porosity and permeability. The interface electrification, adsorption, and specific surface area of the reservoir are positively correlated with the clay mineral content, which is mainly affected by the smectite content. As the clay mineral content increases, the proportion of nanoscale pore throats increases, and the core becomes denser. The saturation of the movable fluid controlled by the >50 nm pore throats in the tight conglomerate ranges from 8.7% to 33.72%, with an average of 20.24%. The clay mineral content, especially the I/S (mixed layer of Illite and montmorillonite) content, is negatively correlated with the movable fluid. In general, the research results clarified the relationship between the lithology and physical properties of clay minerals and the microscopic pore structure of the tight conglomerate reservoirs in the Baikouquan Formation in the Mahu area.

Genesis of authigenic clay minerals and their impacts on reservoir quality in tight conglomerate reservoirs of the Triassic Baikouquan formation in the Mahu Sag, Junggar Basin, Western China

Authigenic clay minerals are widely distributed and considerably affect the reservoir quality of the conglomerate reservoirs in the Triassic Baikouquan Formation (BF), Mahu Sag, Junggar Basin, Western China. Their occurrences, origins, and impacts on reservoir quality were investigated utilizing petrographical analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM), Mercury intrusion capillary pressure (MICP), and fractal analysis. Pore-lining chlorite coatings (Ch1) and pore-filling chlorite aggregates (Ch2), respectively, originate from smectite precursors and directly precipitate from pore water. The first-stage kaolinite (K1) formed by plagioclase dissolution appears as flake-shaped single crystals, whereas the second-stage kaolinite (K2) formed by K-feldspar particle dissolution appears as complete false-hexagonal single crystals and vermiform-shaped aggregates. Smectite transformation produces first-stage illite (I1) with honeycomb-like shaped aggregates. The second-stage illite (I2) displaying a flake-shaped occurrence with a directional arrangement is attributed to the transformation of K-feldspar. Based on the burial history, contact relationship of diagenetic minerals, and hydrocarbon charging period, the paragenetic sequence of the conglomerate reservoir is summarized.Afterward, Neimark's fractal model is employed to calculate the fractal dimensions (Fd) of the reservoir with different dominant clay minerals. It is revealed that pore-lining chlorites have the smallest Fd values (<2.5) and their pore size reached 0.6 μm, whereas pore-filling chlorites possessed the greatest heterogeneity with the narrowest pore size distribution. Illite and kaolinite affect reservoir quality in both favorable and detrimental ways. Eventually, the pore evolution within different lithofacies was analyzed. The first promising reservoirs are well-sorted fine-grained conglomerates that have experienced two phases of oil charging, wherein well-developed primary intergranular apertures, secondary dissolution apertures, and kaolinite are commonly observed. Medium-grained conglomerate reservoirs with high clay amounts and poor sorting have been subjected to rapid and intense compaction, resulting in the worst reservoir quality while no dissolution occurred. This work may provide a useful reference for hydrocarbon exploitation of reservoirs which formed under similar geological conditions.

Production Decline Analysis of Tight Conglomerate Reservoirs with Small Well Spacing, Based on the Fractal Characteristics of Fracture Networks

The conglomerate matrix and fracture propagation are special in tight conglomerate reservoir with small well spacing. In this article, the fractal propagation characteristics of the fracture network in conglomerate reservoirs are described by experiment and a micro-mathematical model. According to the core slice, the conglomerate reservoir matrix presents the multi-modal pore structure, described as the “pseudo-dual-media” model. Given the above, the unsteady seepage mathematical model, comprehensively considering the fractal fracture network, stress sensitivity of main fractures, and threshold pressure gradient of the reservoir matrix, was developed and analytically solved. The Blasingame type curves for production decline analysis were plotted, and the sensitive parameters were analyzed. The field application was performed for validation. The research results show that the fractal dimension decides the complexity of the fracture network distribution. As it increases, the unsteady flow occurs earlier, and the boundary flow is delayed. The anomalous diffusion exponent represents the smoothness of crude oil migration and a higher value leads to higher resistance to oil migration and larger pressure drawdown for the same production rate. The growth of the threshold pressure gradient within a certain range can result in a localized downward shift of the type curves. The field application in a conglomerate oil reservoir showed that the presented model presents a fitting accuracy 10% higher than that of the conventional SRV model and has high reliability and precision for the production performance evaluation of the small-well-spacing development of tight conglomerate reservoirs.

Evaluating the sedimentological and diagenetic impacts on terrestrial lacustrine fan delta sandy conglomerates reservoir quality: Insights from the Triassic Baikouquan Formation in the Mahu sag, Junggar Basin, Western China

The terrestrial lacustrine fan delta conglomerate reservoirs in the Triassic Baikouquan Formation (BF) are the primary hydrocarbon exploration targets in the Mahu sag, Junggar Basin, Western China. However, the varying lithofacies and complex diagenesis controlling the reservoir quality remain poorly understood. For the sake of revealing how reservoir quality is associated with sedimentary processes and diagenetic alterations, we used integrated approaches like petrographical analysis, cores description, wireline, X-ray diffraction (XRD), scanning electron microscopy (SEM), mercury intrusion capillary pressure (MICP) and measured petrophysical properties. The results showed that sedimentary processes have considerable control over facies distribution, grain size, and clay content, causing spatial variation of reservoir quality within the fan delta deposits. The coarser grain and high clay content fraction at the base of gravity flow will first settle in the fan delta plain near provenance, whereas the finer grains at the top of flows progressively deposit in the fan delta front areas. From proximal to distal fan delta, a progressive conversion from cohesive muddy debris flow into traction current can be inferred from the variations of lithofacies associations. A total of 8 types of microfacies were identified where the conglomerates of the BF were deposited. The grayish-green fine-grained conglomerates concentrated in the subaqueous distributary channels provide the best reservoir performance, whereas debris flow deposits dominated primarily by muddy debrites occupy the worst reservoir quality because of their highest clay content and coarsest grain size.The dominant diagenetic events include mechanical compaction that continued throughout the entire burial, two phases of quartz cementation, dissolution of unstable components, early and late carbonate cementation, precipitation of authigenic clay minerals, and two phases of hydrocarbon charging. It is unveiled that compaction is the predominant mechanism negatively affecting reservoir quality in the fan delta complex, while the effect of cementation on pore reduction of the conglomerate reservoir is weaker than compaction. Simultaneously, a complex relationship exists between reservoir petrophysical properties within different clay minerals. Dissolution does not significantly improve the permeability of the reservoir because of the partial dissolution which primarily generated intragranular pores with strong heterogeneity and poor connectivity. The most favorable reservoirs occur primarily in the subaqueous distributary channels in the fan delta front, which comprise well-sorted fine-grained conglomerates with well-developed residual intergranular pores and secondary dissolution pores and have undergone two phases of oil charge. This work may provide a useful reference for hydrocarbon exploration of the fan delta systems and regions which have encountered similar sedimentary and diagenetic processes.

Migration Rule of Crude Oil in Microscopic Pore Throat of the Low-Permeability Conglomerate Reservoir in Mahu Sag, Junggar Basin

The low-permeability conglomerate reservoir in the Mahu Sag has great resource potential, but its strong heterogeneity and complex microscopic pore structure lead to a high oil-gas decline ratio and low recovery ratio. Clarifying the migration rule of crude oil in microscopic pore throat of different scales is the premise of efficient reservoir development. The low-permeability conglomerate reservoir of the Baikouquan Formation in the Mahu Sag is selected as the research object, and two NMR experimental methods of centrifugal displacement and imbibition replacement are designed to reveal the differences in the migration rule of crude oil in different pore throats. According to the lithology and physical properties, the reservoirs in the study area can be divided into four categories: sandy grain-supported conglomerates, gravelly coarse sandstones, sandy-gravelly matrix-supported conglomerates and argillaceous-supported conglomerates. From type I to type IV, the shale content of the reservoir increases, and the physical property parameters worsen. Centrifugal displacement mainly produces crude oil in large pore throats, while imbibition replacement mainly produces crude oil in small pores. In the process of centrifugal displacement, for type I reservoirs, the crude oil in the pore throats with radii greater than 0.5 μm is mainly displaced, and for the other three types, it is greater than 0.1 μm. The crude oil in the pore throats with radii of 0.02–0.1 μm, which is the main storage space for the remaining oil, is difficult to effectively displace. The crude oil in the pore throats with radii less than 0.02 μm cannot be displaced. The two experimental methods of centrifugation and imbibition correspond to the two development methods of displacement and soaking in field development, respectively. The combination of displacement and soaking can effectively use crude oil in the full-scale pore throat space to greatly improve the recovery of low-permeability conglomerate reservoirs.