Tight Clastic Reservoirs Research Articles

Gas-bearing prediction of tight clastic rock reservoirs based on random forest-modern temporal convolutional network

Reservoir gas-bearing identification is a crucial link in natural gas exploration and development. However, under the conditions of sparse well distribution, challenges such as insufficient prior information and low identification accuracy often arise. In response, we have developed a method for identifying the gas-bearing of tight clastic reservoirs based on the fusion of well logging and seismic data. Initially, feature engineering processing is applied to P-wave slowness, S-wave slowness, and density to calculate petrophysical parameters and fluid indicators, using the random forest algorithm to refine reservoir-sensitive parameters. Subsequently, a deep-learning network named modern temporal convolutional network (ModernTCN) is constructed, which uses reservoir-sensitive parameters as inputs for model training and testing. This network features a decoupled design to segregate temporal and feature information, effectively capturing the longitudinal gas-bearing characteristics of the reservoir. Next, we compare the ModernTCN with a fully convolutional network, a multiscale fully convolutional network, a self-attention bidirectional long short-term memory network, a self-attention bidirectional gated recurrent unit, and a 1D deep residual network to determine the reliability of this method. Furthermore, a probabilistic weighted voting algorithm based on the multi to single strategy captures the spatial correlation among adjacent seismic traces to predict lateral distribution characteristics of the reservoir. Ultimately, the methodology is applied using seismic and well data from the Huangyan structural belt of Xihu Sag, China, to identify gas-bearing zones in tight clastic rock reservoirs. The results are validated through the reflection characteristics of the test well logs and along-horizon slicing. This approach determines substantial well-seismic concordance, confirming its potential to support the exploration and development of tight clastic gas reservoirs.

Evaluation of the Lower Cretaceous Alam El Bueib Sandstone reservoirs in Shushan Basin, Egypt – Implications for tight hydrocarbon reservoir potential

This study presents the evaluation of the potential reservoir intervals in the early Cretaceous Alam El Bueib Formation of the Shushan Basin, Western Desert. Seismic 2D lines, and wireline logs (including image logs) were assessed to characterize the potential intervals. The study area is characterized by E-W to ENE-WSW striking parallel sets of steeply dipping normal faults. Based on the breakouts on image log, the regional maximum horizontal stress orientation is inferred as NE-SW. The AEB Formation, as observed on the image log, consists of massive sandstones, planar laminated siltstones, sandstone-siltstone heteroliths and laminated shales, deposited in a fluvial depositional environment. The bedding planes are WNW-ESE striking with a mean true dip of NNE (around 10°). Wireline log based quantitative petrophysical assessment identified multiple promising hydrocarbon-bearing reservoir intervals within the AEB Formation. The potential reservoir intervals are clean with shale content <10% with water saturation <50%. However, all these intervals are tight with effective porosity between 4 and 12%, dominantly ∼5%. Such tight effective porosity can be contributed by extensive silica cementation in the AEB Formation, as seen from the nearby fields in Western Desert. High porosity zones are observed to be water-bearing. The wells drilled in the north and northeastern area exhibit a cumulative net pay thickness between 70 and 150 ft, while south-southeastern region exhibits a very low cumulative net pay of 10–30 ft. Based on the breakout son image log, the regional minimum horizontal stress orientation is inferred as NW-SE, which can be preferred azimuth for placing highly deviated or horizontal wells to exploit such tight clastic reservoirs by optimizing hydraulic fracture propagation. The formation evaluation presented in this work shed critical insights into the tight hydrocarbon reservoir potential of the early Cretaceous AEB.

Quantifying the Microdistribution of Different Fluid Types in the Multiscale Pore Throat Structure of Low-Permeability Conglomerates

The volumes of different fluid types and the pore throat structure in low-permeability reservoirs are crucial parameters for understanding flow mechanisms and predicting production performance. The previously applied methods for distinguishing different fluid types are mainly based on T2 spectra under saturated, centrifugal, and heat-treated conditions. However, for rocks with different mineral compositions and pore structures, the critical temperature between capillary-bound fluid (CAF) and clay-bound fluid (CLF) differs from 60 to 100 °C. Moreover, the alteration of temperature can cause the transformation of clay minerals and a change in a nanopore structure. Herein, an improved method that integrates nuclear magnetic resonance (NMR) tests (n-dodecane-saturated, centrifugal, and spontaneous imbibition treatment conditions) and multicycle mercury intrusion porosimetry, was proposed for quantitatively evaluating the microdistributions of different fluid types, classifying the pore throat system, and analyzing the relationship between pore throat structure and different fluid types in low-permeability conglomerates. Based on the fractal characteristics and mercury intrusion/extrusion characteristics of pore throats at different scales, the pore throat system in these conglomerates was divided into macropore throats (>1 μm), mesopore throats (0.2–1 μm), and micropore throats (<0.2 μm). Macropore throats are connected to intergranular pores (>100 ms); mesopore throats are mostly connected to intergranular pores and intragranular dissolved pores (>10 ms); and micropore throats are connected to intragranular dissolved pores (<10 ms) and clay-related pores (<3 ms). The proportions of movable fluid, CAF, and CLF in the low-permeability conglomerates are 20.4–57.4%, 6.67–32.2%, and 36.0–47.4%, respectively. The movable fluids are mainly distributed in macropore throats and mesopore throats. CAF mainly exists in the micropore throats (pore throat radius <0.2 μm and pore size <10 ms). CLF is mainly distributed in pores with T2 < 3 ms, that is clay-related pores. The improved method of fluid typing is suitable for low-permeability or tight clastic reservoirs (excluding shale).

The Impact of Clay Minerals on the Porosity Distribution of Clastic Reservoirs: A Case Study from the Labuan Island, Malaysia

Clay mineral content and diagenetic processes are vital factors that affect reservoir quality, especially in tight clastic reservoirs, which are crucial for industrial and scientific purposes. The presence of clay minerals poses one of the most significant challenges in evaluating sandstone reservoirs’ quality. Even though wireline logs may provide a good indication of the reservoir quality, there have been cases where they have failed. This work focuses on the clay minerals’ impact on the porosity and permeability of a clastic reservoir. Typical outcrops from Labuan Island, Brunei–Sabah Basin, were chosen as a case study to investigate the petrophysical and petrographic parameters together with clay mineralogy profiling. The effects of the clays on the petrophysical parameters of the sandstone reservoir were evaluated through air permeability, spectral gamma ray measurements, a petrographic thin section analysis, a visual porosity estimation, and a grain size analysis. Field and petrographic studies revealed that Belait and Temburong formations contain massive, interbedded, laminated, and cross-bedded sandstones. Using an image analysis of the thin sections, porosity values ranged from 7.3% to 23.5%, with different macro and micro porosity distributions. According to the spectral gamma-ray investigation and air permeability, permeability reduction is strongly associated with clay minerals. The microporosity and permeability of the analyzed samples showed a unique pattern influenced by the grain size distribution. It was found that the textures dominated by mud grain size had a more significant impact on the air permeability and visual porosity, with coefficient of determination values of 0.83 and 0.70, respectively. The Belait Formation displayed a higher porosity and permeability compared to the Temburong Formation. This research provides new insight into the potential reservoir of Stage IV (the Belait Formation offshore equivalent) compared to Stage II (the Temburong Formation offshore equivalent).

Effect of Authigenic Chlorite on the Pore Structure of Tight Clastic Reservoir in Songliao Basin.

Authigenic chlorite is a common clay mineral in clastic rock reservoirs, and it has an important influence on the pore structure of tight clastic rock reservoirs. In this paper, the tight clastic reservoirs in the Lower Cretaceous Yingcheng Formation in the Longfengshan subsag in the Changling fault depression in the Songliao Basin were investigated. Polarized light microscopy, scanning electron microscopy (SEM), X-ray diffraction (XRD), high-pressure mercury injection (HPMI), and low temperature nitrogen adsorption (LTNA) were used to study the influence of authigenic chlorite on the pore structure of tight clastic reservoirs. The results show that the authigenic chlorite in the study area was mainly generated in the form of pore linings. The formation of the authigenic chlorite was mainly controlled by the parent rock type and the sedimentary microfacies in the provenance area. The hydrolysis and dissolution of the iron- and magnesium-rich intermediate-mafic magmatic rocks and the high-energy, open, weakly alkaline reducing environment in the delta-front underwater distributary channel were the key factors controlling the formation of the authigenic chlorite in the study area. The pore-lining chlorite slowed down compaction and inhibited quartz overgrowth, protecting the original pores. Moreover, there are a large number of intercrystalline pores in the chlorite, which provided channels for the flow of acidic water and thus the formation of secondary pores, playing a positive role in the physical properties of the tight clastic rock reservoirs. However, the pore-filling chlorite also blocked the pore throats, playing a negative role in the physical properties of the tight clastic rock reservoirs. The tight clastic rock reservoirs with pore-lining chlorite generally had low displacement pressures and large pore throat radii. The morphology of the nano-scale pores was mainly parallel plate-shaped slit pores. There were many primary pores and a small number of secondary pores in the reservoir. Some of the pores were connected by narrow-necked or curved sheet-like throats, and the pore structure was relatively good. A higher relative content of chlorite led to a larger nano-scale pore throat radius, a smaller specific surface area, a smoother pore surface, and stronger homogeneity. Authigenic chlorite played a positive role in the formation of the tight clastic reservoirs in the study area.

Spatial Characteristics and Genesis of Tight Clastic Reservoirs in Yingcheng Formation of Changling Fault Depression in the Southern Songliao Basin

Tight oil and gas has become a hot spot for unconventional oil and gas exploration. How to find high-quality reservoirs under the conditions of low porosity and permeability has become a key issue restricting tight oil and gas exploration. This paper takes the deep-seated tight clastic rocks in the Changling fault depression in the Songliao Basin as the research object and comprehensively applies various technologies and methods such as microscopic observation, temperature measurement of inclusions and paleopressure recovery, and water-rock simulation experiments, to summarize the storage of tight reservoirs. Set space types and analyze their formation mechanism. The research results show that (1) the tight clastic reservoir space types of Yingcheng Formation in the Longfengshan subsag of the Changling fault depression in the southern Songliao Basin include residual primary pores, secondary dissolved pores, and microfractures, with mainly secondary dissolved pores; (2) pore lining chlorite is an important mechanism for the preservation of primary pores; (3) water-rock simulation experiments have confirmed that volcanic rock cuttings are easy to dissolve and are the main contributor to the secondary dissolution pores in the study area; and (4) the Raman displacement technique of methane inclusions has confirmed the existence of overpressure, which is the cause of hydrocarbon generation and pressurization and is the main motivation for a microcrack formation.

The Accumulation Characteristics of the Paleozoic Reservoir in the Central-Southern Ordos Basin Recorded by Organic Inclusions

The Permian tight clastic reservoir and Ordovician carbonate reservoir were developed in the central-southern Ordos Basin. This study investigated the fluid inclusion petrography, diagenetic fluid characteristics, formation process of natural gas reservoir, source rock characteristics, and reservoir accumulation characteristics of these Paleozoic strata by petrographic observations, scanning electron microscope imaging, fluid inclusion homogenization temperature, salinity, laser Raman spectrum, and gas chromatograph analyses. The results have suggested two phases of fluid inclusions in both the Permian sandstone and the Ordovician Majiagou Formation dolomite reservoirs, and the fluid inclusions recorded the history from the early thermal evolution of hydrocarbon generation to the formation, migration, and accumulation of natural gas. The early-phase inclusions show weak yellow fluorescence and recorded the early formation of liquid hydrocarbons, while the late-phase inclusions are nonfluorescent natural gas inclusions distributed in the late tectonic fractures and recorded the late accumulation of natural gas. The brine systems of the Permian and Ordovician fluid inclusions are, respectively, dominated by CaCl2-H2O and MgCl2-NaCl-H2O. The diagenetic fluids were in the ranges of medium-low temperature and moderate-low salinity. The natural gas hydrocarbon source rocks in the Ordos Basin include both the Permian coal-bearing rocks and the Ordovician carbonates. The process of the early-phase liquid hydrocarbon formation and migration into the reservoir corresponded to 220 Ma (Late Triassic). The late large-scale migration and accumulation of natural gas occurred at 100 Ma (early Late Cretaceous), which was close to the inclusion Rb/Sr isochron age of 89.18 Ma, indicating that the natural gas accumulation was related to the Yanshanian tectonic movement.

Stress sensitivity of tight reservoirs and its effect on oil saturation: A case study of Lower Cretaceous tight clastic reservoirs in the Hailar Basin, Northeast China

To analyze stress sensitivity of tight reservoirs and the boundary conditions for oil filling, core samples of tight clastic reservoirs in the Lower Cretaceous Nantun Formation in the Hailar Basin were selected. The measurements include optical observation of thin sections, changes of porosity and permeability under overburden pressure, together with physical simulation experiments of oil filling. The results show that the stress sensitivity coefficient of permeability is a product of two parameters including the power exponent of porosity-permeability and pore compressibility, which reflect the geometric and mechanical characteristics of pores. The stress sensitivity and pore geometry of tight reservoirs of different lithologies vary greatly. Medium-coarse sandstones-conglomerates have relatively small stress sensitivity coefficient and large power exponent of porosity-permeability, indicating stronger anti-compaction, weaker stress sensitivity and dominated fissure-type pores. Fine sandstone with large stress sensitivity coefficient and small power exponent of porosity-permeability, indicating that stress sensitivity is high, and matrix circular/elliptical pores predominate. Oil filling in tight reservoirs displays two pressure gradient points with threshold characteristics (i.e., starting pressure gradient and critical pressure gradient) and two flow characteristics (i.e., low-speed nonlinear seepage and quasi-linear seepage). Only when the actual pressure gradient breaks through the critical pressure gradient into the quasi-linear seepage zone can oil saturation in the tight reservoir reach the lower limit of 30%, attaining higher oil saturation levels gradually during the subsequent filling process. The favorable tight reservoir is characterized by a low stress sensitivity coefficient and a high power exponent of porosity-permeability, and oil exhibits rapid filling characteristics with quasi-linear seepage. Another type of tight reservoir is characterized by a high stress sensitivity coefficient and a low power exponent of porosity-permeability, and oil exhibits slow filling rate with nonlinear seepage. It is therefore difficult in actual geological conditions for such reservoirs to achieve high oil saturation. Increase in oil saturation during the filling process is controlled by a combination of initial permeability, pore geometry, stress sensitivity and the displacement pressure gradient. These factors affect and compensate each other, comprehensively controlling the accumulation of tight oil, and could be used to classify the reservoir types.

Diagentic features of illite in Upper Triassic Chang-7 tight oil sandstones, Ordos Basin

The Upper Triassic Chang-7 tight oil sandstones are the main tight clastic reservoirs in the Ordos Basin, central China. Illite is one of the most important cements affecting porosity and permeability of the tight oil sandstones, and this study focuses on different types of illitization and its relative formation time. The Chang-7 tight sandstones are mainly fine-grained lithic arkose and feldspar lithic sandstones, rich in mica and illite (hydrous mica). They are formed in distal delta front to semi-deep and deep lake facies, mainly deposited in a low energy environment. Porosity and permeability are very low (average porosity 8.58% and permeability 0.20 mD). The illite has many morphological characteristics and is multiphase, incorporating six types of illitization: hydrous mica, mica, and smectite illitization at the eodiagenetic stage, and kaolinite and K-feldspar illitization, and neoformation illite particles, at the mesodiagenetic stage. These different types of illitization are mainly controlled by sedimentary environment and provenance. Quartz overgrowth and diagenetic illites appear to be locally mutually exclusive, competing for detrital grain surfaces, but neoformation illite particles appear to form on the quartz overgrowth. The systematic study of Upper Triassic Chang-7 tight oil sandstones carried out here, enhances our understanding of illitization and the diagenetic model of the Ordos Basin, and contributes to reducing the exploration risk of continental tight sandstone reservoirs.

NMR logging activation sets selection and fluid relaxation characteristics analysis of tight gas reservoirs: A case study from the Sichuan Basin

With complex lithology and reservoir types, as well as high concealment and heterogeneity, tight reservoirs in the Sichuan Basin involve significant uncertainties in gas–water relationship. Since NMR logging can effectively solve problems related to the multiple results of conventional logging operations, it can be deployed for accurate assessment of the properties of formation fluids. Accordingly, different NMR logging activation sets were assessed in accordance with the specific features of tight reservoirs in the basin. With consideration to NMR logging data obtained under different activation sets and testing data of wells, the optimal NMR logging activation set was identified. Moreover, with relaxation characteristics of rocks, gas and water as theoretical foundations, the T2 gas and water relaxation characteristics were reviewed to highlight the impacts of porosity, pore sizes, fluid properties and other factors of tight reservoirs on T2 horizontal relaxation distribution. According to the research results, D9TWE3 can be seen as the most suitable NMR logging activation set for tight reservoirs in the Sichuan Basin; reservoir tightness is the key influence factor for the distribution of gas/water relaxation in tight clastic reservoirs; generally, in tight sandstone reservoirs, natural gas shows a longer T2 relaxation time than water; in fracture-vug type carbonate reservoirs, the right peak of T2 distribution spectrum of gas layers is frontal, while the right peak in T2 distribution spectrum of water layers is backward. In conclusion, the standards for gas/water relaxation in tight sandstone and carbonate reservoirs in the Sichuan Basin can help effectively determine the physical properties of fluids in tight reservoirs with porosity of 4–10%. Such standards provide reliably technical supports for gas/water identification, reserves estimation and productivity construction in tight reservoirs of the Sichuan Basin.

Origin of different chlorite occurrences and their effects on tight clastic reservoir porosity

The effects of chlorite on tight sandstone reservoirs have not been fully understood yet. In this paper, two different chlorite occurrences are observed in the Upper Triassic Xujiahe tight sandstones of Guang'an Area, Sichuan Basin (grain coating) and in the Permian Lucaogou tight sandstones of Jimusar Sag, Junggar Basin (pore filling), respectively. The effects these two chlorite occurrences having on reservoir quality are evaluated. Results show the influence of chlorite on porosity of tight clastic reservoir depends on its occurrences. Grain-coating chlorite has positive effect on porosity preservation, while pore-filling chlorite plays a negative role.Analysis of grain size indicates that grain-coating and pore-filling chlorites always occur in high-energy and low-energy environments, respectively. The water current carries an abundance of medium-grained saltating contents in strong hydrodynamic tractive current environment that leads to a relative motion between the saltating population and suspended clay in water. As indicated by Bernoulli's theory, the saltating grains are coated by clay on the surface because of the local flow pressure resulting from relative velocity. However, in the case of a weak hydrodynamic tractive current depositional environment, sand is entrained with clay, i.e., both sand grains and clays are in suspension and they have no relative velocity; thus, the clay cannot completely coat the grain surface. As the precursor of chlorite, occurrence of smectite-dominant clays determines the occurrence of chlorite during diagenesis, and therefore, determines whether the chlorite has a positive effect on porosity of tight clastic reservoirs.

Study on the improving method for gas production prediction in tight clastic reservoir

Relative permeability and resistivity index are important parameters for the exploration and development in a tight sandstone gas field. In the splitting method which uses permeability (K), reservoir thickness (H), and relative permeability (K), briefly referred to as the KHK splitting method, the accuracy of the relative permeability is crucial. According to the relationship between resistivity index and relative permeability of the Mesozoic Lower Safa Formation at Obaiyed Field in the Western Desert of Egypt, we improved the split method and made it more in line with the real situation by adopting Pairoys’ model which is more suitable to our study area. In this paper, we use a radial basis function (RBF) to establish the relationship between logging data and the gas production split point to point in tight sandstone gas reservoirs. To compare with the result by support vector regression (SVR), our method is better as indicated by mean absolute error values. In order to solve the problem that the relative permeability is difficult to obtain in the well logging evaluation, we also provide a convenient method and application example.

A new method for assessing Young's modulus and Poisson's ratio in tight interbedded clastic reservoirs without a shear wave time difference

Tight clastic reservoirs are an important aspect of hydrocarbon exploration and development worldwide. The Xu5 section of the Upper Triassic Xujiahe Formation in the western Sichuan Basin of central China contains tight terrestrial clastic reservoirs. The depth of these reservoirs is greater than 3000 m, while the thickness is generally greater than 500–580 m; the tight sandstone and shale reservoirs are frequently interbedded. Based on the proportion of sandstone and shale, the reservoirs can be divided into four types: sand-rich, interbedded Type I, interbedded Type II, and shale-rich. Horizontal wells and multistage fracturing are used due to the complexity and significant heterogeneity of the tight clastic reservoirs in the study area. The Young's modulus and Poisson's ratio of the reservoir rocks are the two most significant parameters that must be evaluated when implementing these key techniques. Based on mechanical and acoustic tests, a new assessment system for the Young's modulus and Poisson's ratio based on the Hoek-Brown criterion was proposed. This evaluation system does not require the shear wave time difference; thus, the increase in error caused by the unreliability of the shear wave time difference can be avoided when assessing strata with complex geological structures. This method can be directly applied in single wells using only conventional longitudinal wave time difference log data. After converting the wave velocity of the high experimental frequency into the wave velocity of the logging frequency using the acoustic dispersion technique, the analysis results were applicable to the log evaluations. The relationship between the Hoek-Brown criterion parameters and the mechanical and acoustic parameters of the rock were systematically analyzed. By distinguishing the lithologies, the equations for the Young's moduli of tight sandstones and shales were established based on the Hoek-Brown criterion. The Young's modulus can be expressed using only the longitudinal wave velocity (VP). A significant negative correlation exists between the Poisson's ratio and Young's modulus; therefore, the Poisson's ratio can be evaluated from the Young's modulus. The errors of the Young's modulus and Poisson's ratio predicted by the proposed assessment method are small, which meets engineering requirements and validates the accuracy of the method.

Sulige field in the Ordos Basin: Geological setting, field discovery and tight gas reservoirs

The Sulige gas field in central Ordos Basin is one of the largest gas fields in China, with about 860.7 billion cubic meters (bcm) of proven gas reserve. This field covers an area of about 500 km 2, with largely tight clastic reservoirs. The Upper Carboniferous–Lower Permian deltaic sandstones and Upper Permian lacustrine mudstones deposited in a stable cratonic tectonic setting form an effective petroleum system that is favorable for gas accumulation in large-scale stratigraphic–lithologic traps. Based on wire line log response, drilling stem test and core data, a generalized classification system was developed for the gas reservoirs of the Sulige field, thus Type I and II rocks are capable of gas production without natural and/or artificial fracturing, Type III rocks are capable of gas production after artificial fracturing and Type IV rocks are too tight to produce at commercial rates even with artificial fracturing. The discovery of the Sulige field not only adds large gas reserve in the Ordos Basin, but strongly indicates the overlook potential of both tight sandstone reservoir rock and relatively porous and permeable sweet spots in it.