Gas Reservoir Characterization Research Articles

Fast prediction method of tight gas production based on segmented decline

The physical properties of tight gas reservoirs are poor. During the stable production period of gas wells, most of the recoverable reserves are produced in the declining stage. It is of great significance to accurately study the declining law of tight gas. However, tight gas production declines rapidly in the early stage and slower in the middle and late stages, and the single model fitting and prediction results have large errors. In view of the above problems, according to the production change characteristics of tight gas wells, the decline stage is divided into three stages, and a segmented production decline law analysis method is established. The research results show that the early production decline of tight gas wells is exponential decline, the relatively slow middle-term production decline belongs to depletion decline, and the late production decline belongs to linear decline. Based on the study of the law of production decline, a gas reservoir production prediction software was compiled, and the production variation characteristics of single wells and gas reservoirs under certain stable production requirements were studied.

Research on Quantitative Evaluation Methods and Influencing Factors of Natural Gas Reservoir Development

Current methods of evaluating the effects of gas reservoir exploitation primarily focus on evaluating production statistics of a well or field, and they often have a certain subjectivity. In order to further analyze key indexes that affect a gas reservoir during production, this paper considered the characteristic parameters of different types of gas reservoirs and established an index system of evaluating a gas reservoir “exploitation effect” from the three aspects of gas reservoir characteristics, rock characteristics, and economic benefits. There are numerous factors affecting the exploitation effect of a gas reservoir. The relationships between different factors are complicated, and the evaluation result of each factor can also be vague. A fuzzy optimization theoretical model for gas reservoir evaluation and optimization was established on the basis of a quantitative study on the evaluation parameters in fuzzy mathematics. In order to clearly understand the influence of each factor on the gas reservoir exploitation effect, numerical simulation was used to perform a multifactor numerical simulation study of the quantitative sensitivity to determine the sequence of different influencing factors in terms of influencing the gas reservoir exploitation effect. This study provides a quantitative scientific basis for the evaluation of gas reservoir exploitation effect.

Characterization of a Volcanic Gas Reservoir Using Seismic Dispersion and Fluid Mobility Attributes

Abstract Seismic dispersion and fluid mobility attributes are used to characterize a volcanic gas reservoir in the Songliao Basin of China. A rock physics model is constructed to describe poroelastic behaviors associated with heterogeneous fluids saturation within the volcanic gas reservoirs, where velocity dispersion and attenuation of propagating waves are attributed to the wave-induced fluid flow described by the patchy saturation theory. Modeling results indicate that the frequency-dependent bulk modulus at the seismic frequency is more sensitive to gas saturation than the P-wave velocity dispersion. Accordingly, a new inversion method is developed to compute bulk-modulus-related dispersion attribute DK for improved characterization of volcanic gas reservoirs. Synthetic tests indicate that DK is more sensitive than traditional P-wave dispersion attribute DP to the variations of reservoir properties. The high value of dispersion attribute DK indicates the volcanic gas reservoirs with high porosity and gas saturation. At the same time, fluid mobility attribute FM can discriminate the volcanic gas reservoir as DK. Field data applications illustrate that DK and FM exhibit anomalies to the gas zones in the volcanic gas reservoir on the cross-well section. However, DK is more robust than FM to identify favorable zones on horizontal slices for specific target layers. Overall, rock physical modeling provides insights into the poroelastic behaviors of volcanic gas reservoirs, and inversion for seismic dispersion attribute DK improves hydrocarbon detection in the volcanic gas reservoir.

Dynamic streaming potential coupling coefficient in porous media with different pore size distributions

SUMMARY Seismoelectric signals are generated by electrokinetic coupling from seismic wave propagation in fluid-filled porous media. This process is directly related to the existence of an electrical double layer at the interface between the pore fluid and minerals composing the pore walls. The seismoelectric method attracts the interest of researchers in different areas, from oil and gas reservoir characterization to hydrogeophysics, due to the sensitivity of the seismoelectric signals to medium and fluid properties. In this work, we propose a physically based model for the dynamic streaming potential coupling coefficient (SPCC) by conceptualizing a porous medium as a bundle of tortuous capillaries characterized by presenting different pore size distributions (PSD). The results show that the dynamic streaming potential coupling coefficient is a complex function depending on the properties of pore fluid, mineral–pore fluid interfaces, microstructural parameters of porous media and frequency. Parameters influencing the dynamic SPCC are investigated and explained. In particular, we show that the PSD affects the transition frequency as well as the shape of the SPCC response as a function of frequency. The proposed model is then compared with published data and previous models. It is found that the approach using the lognormal distribution is in very good agreement with experimental data as well as with previous models. Conversely, the approach that uses the fractal distribution provides a good match with published data for sandstone samples but not for sand samples. This result implies that the fractal PSD may not be pertinent for the considered sand samples, which exhibit a relatively narrow distribution of pore sizes. Our proposed approach can work for any PSD, for example, including complex ones such as double porosity or inferred from direct measurements. This makes the proposed models more versatile than models available in literature.

Elastic Reverse-Time Migration with Complex Topography

Migration is an important step in seismic data processing for oil and gas exploration. The accuracy of migration directly affects the accuracy of subsequent oil and gas reservoir characterization. Reverse-time migration is one of the most accurate migration methods at present. Multi-wave and multicomponent seismic data contain more P- and S-wave information. Making full use of multi-wave and multicomponent seismic data can offer more information about underground structure and lithology, as well as improve the accuracy of seismic exploration. Elastic reverse-time migration (ERTM) has no dip restriction and can be applied to image multi-wave and multicomponent seismic data in complex structural areas and some special lithology structures. However, the surface topography of complex regions has an influence on wavefield and seriously degrades the quality of ERTM’s migration results. We developed a new ERTM method to migrate multi-wave and multicomponent seismic data in the region with complex surface topography. We first fill the layers between the highest and lowest undulating surface with near-surface elastic parameters in a complex topography model to obtain a new model with a horizontal surface. This allows the finite difference (FD) method based on the regular rectangular grid to be used to numerically solve elastic wave equations in the model with complex topography. The decoupled wave equations are used to generate source P- and S-waves and receiver P- and S-waves to reduce crosstalk artefacts in ERTM. A topography-related filter is further used to remove the influence of surface topography on migration results. The scalar imaging condition is also applied to generate PP and PS migration images. Some numerical examples with different complex topographies demonstrate that our proposed ERTM method can remove the influence of complex topography on ERTM’s images and effectively generate high-quality ERTM images.

Microcrack Porosity Estimation Based on Rock Physics Templates: A Case Study in Sichuan Basin, China

Low porosity-permeability structures and microcracks, where gas is produced, are the main characteristics of tight sandstone gas reservoirs in the Sichuan Basin, China. In this work, an analysis of amplitude variation with offset (AVO) is performed. Based on the experimental and log data, sensitivity analysis is performed to sort out the rock physics attributes sensitive to microcrack and total porosities. The Biot–Rayleigh poroelasticity theory describes the complexity of the rock and yields the seismic properties, such as Poisson’s ratio and P-wave impedance, which are used to build rock-physics templates calibrated with ultrasonic data at varying effective pressures. The templates are then applied to seismic data of the Xujiahe formation to estimate the total and microcrack porosities, indicating that the results are consistent with actual gas production reports.

Experimental Study on Enhanced Condensate Recovery by Gas Injection in Yaha Condensate Gas Reservoir

A condensate gas reservoir is an important special oil and gas reservoir between oil reservoir and natural gas reservoir. Gas injection production is the most commonly used development method for this type of gas reservoir, but serious retrograde condensation usually occurs in the later stages of development. To improve the recovery efficiency of condensate oil in the middle and late stages of production of a condensate gas reservoir, a gas injection parameter optimization test study was carried out, taking the Yaha gas condensate reservoir in China as an example. On the premise that the physical experimental model and key parameters met the actual conditions of the formation, the injection method, injection medium, injection-production ratio, and other parameters of the condensate gas reservoir were studied. Research on the injection method showed that the top injection method had a lower gas-oil ratio and higher condensate oil recovery. The study of injection medium showed that the production effect of carbon dioxide (CO2) injection was the best injection medium, and the maximum recovery rate of condensate oil was 95.11%. The injection-production ratio study showed that the injection-production ratio was approximately inversely proportional to the recovery factor of condensate gas and approximately proportional to the recovery factor of condensate oil. When the injection-production ratio was 1 : 1, the maximum recovery rate of condensate oil was 83.31%. In summary, in the later stage of gas injection development of the Yaha condensate gas reservoir, it was recommended to choose the development plan of CO2 injection at the top position with an injection-production ratio of 1 : 1. This research can not only provide guidance for the later formulation of gas injection plans for Yaha condensate gas reservoirs but also lay a foundation for the research of gas injection migration characteristics of other condensate gas reservoirs.

Difference in pore structure characteristics between condensate and dry shale gas reservoirs: Insights from the pore contribution of different matrix components

A breakthrough in shale gas exploration was made in the lacustrine shale of Qianfoya Formation located in the Sichuan Basin; a gas analysis has shown that the reservoir therein is a condensate gas reservoir. To enhance the production of shale gas in the Sichuan Basin, reduce the exploration risk, and facilitate development, the marine dry gas shale of the Longmaxi Formation was selected as a comparison to analyze the pore structure characteristics of condensate and dry gas reservoirs. The results showed that the dry gas shale reservoir is mainly developed as organic matter (OM) pores, followed by clay mineral (CM) pores. In condensate gas shale reservoirs, the OM pores, CM pores, intragranular dissolution (ID) pores, and microfractures are common. In the dry gas shale reservoir, the surface porosities of the organic matter, clay minerals, brittle minerals, and microfractures were 10%–65%, 0%–23%, 0%–22%, and 0%–13%, respectively. Micropores were mainly provided by OM pores; mesopores were mainly provided by OM and CM pores; macropores were mainly provided by OM, CM, and ID pores. In the condensate gas shale reservoir, the surface porosities of the organic matter, clay minerals, brittle minerals, and microfractures were 0%–52%, 6%–34%, 0%–18%, and 0%–21%, respectively. Micro-mesopores were mainly provided by OM and CM pores, while macropores were mainly provided by CM pores and microfractures. Because of the influences of material composition, diagenetic evolution, and hydrocarbon generation at the burial depth, there were significant differences in the surface porosities of the matrix components and the distribution and proportions of the different pores between the dry and condensate gas shale reservoirs. This essentially led to a difference in the reservoir space.

Research and Application of EUR Prediction Method for Tight Sandstone Gas Wells: Taking Bajiaochang Shaximiao Formation Gas Reservoir as an example

Tight gas is currently an important area for the exploration and development of unconventional oil and gas resources at home and abroad. However, due to the low permeability and high-water saturation characteristics of tight gas reservoirs, gas wells exhibit low productivity, rapid decline in production, and water production in some wells. Such characteristics have reduced the single-well EUR to a certain extent, affecting the recovery rate of the gas reservoir. For new blocks, single-well EUR is the basic condition for long-term high and stable production of oil and gas wells. It is an important indicator for evaluating development effects, analyzing development potential, and formulating development-specific measures. How to quickly and accurately predict and analyze single-well EUR has always been tight Important research work for the development of gas. This paper takes the tight sandstone gas reservoir in the Bajiaochang block as an example. Based on the analysis of the production characteristics of the implemented wells, the production instability analysis method is used to analyze the variation rules and control factors of the single well EUR at different stages, and establish a single well EUR forecast analysis. plate. The analysis results show that the single-well EUR calculation result is more reliable for more than 2 years of continuous production, and can reach more than 80% of the final value. This method provides convenience for the rapid and accurate prediction of single-well EUR, and has a better field application effect.

Study on Formation Conditions and Distribution Characteristics of Deep Oil and Gas Reservoirs Based on Computer Software Analysis

Conventional reservoirs can be formed in the layers with relatively high quality reservoir sections, while unconventional reservoirs such as tight reservoirs can be formed in tight layers. This paper systematically studies and analyzes the formation conditions and distribution characteristics of deep oil and gas reservoirs by using the software analysis ability of computer. Oil and gas reservoir is the basic unit of oil and gas accumulation in the earth’s crust. A reservoir exists in an independent trap, in which oil and gas have a certain distribution law and a unified pressure system. Through the computer-aided understanding and calculation of the formation and distribution of oil and gas reservoirs, energy can be found more effectively, which helps to expand the national energy reserves [1].

Transverse permeability measurements of gas shales under replicated in-situ flow conditions: Mathematical modeling and laboratory testing

Fast and accurate characterization of unconventional gas reservoirs is of great significance for estimation of gas-in-place and enhancement of gas recovery; however, it remains a big challenge to efficiently and effectively determine the permeability of tight-structure reservoirs in the nano-Darcy scale, especially for those reservoirs with strong gas sorption potential. A novel pressure transient technique is proposed to replicate the in-situ gas flow behavior, and thus to reduce the permeability errors from gas compressive storage, gas sorption, and gas compressibility, which are the three primary error sources widely existing in various permeability measurement techniques. The feasibility of the technique is firstly verified via numerical solutions of a partial differential equation (PDE) model established to closely represent the proposed technique. The results of the numerical study showed that the effects of the error sources on the measured permeability can be minimized and meanwhile, high accuracy and efficiency can be achieved in comparison with the conventional method. A specially designed apparatus for experimental tests via the proposed technique is then used to investigate the stress-dependent permeability of gas shales. The consistency of the experimental results with the findings from the numerical study further validates the applicability of the technique. Considering the complexity of the analytical solution of the PDE model for experimental data interpretation, shale permeability is computed via a new data interpretation approach which is developed by combining the curve-matching and the finite difference method. The experimental results showed that shale permeability is strongly dependent upon the applied stresses and easily affected by gas sorption, gas compressibility and stress inhomogeneity. Without consideration of these factors, the permeability error can reach up to 28.1 % at low stresses. The proposed technique provides a great tool to get insights into the in-situ gas flow behavior and characterize tight-structure gas reservoirs.

Tight gas reservoir characteristics and exploration potential of Jurassic Ahe Formation in Kuqa Depression, Tarim Basin#br#

Tight gas reservoir characteristics and exploration potential of Jurassic Ahe Formation in Kuqa Depression, Tarim Basin#br#

Comparative Study on the Reservoir Characteristics and Development Technologies of Two Typical Karst Weathering-Crust Carbonate Gas Reservoirs in China

Carbonate reservoirs are the main reservoir types in China, which occupy the large ratio of reserves and production at present. The high-efficiency development of carbonate reservoirs is of great significance to assure the stability of national energy supply. The Lower Paleozoic reservoir in Jingbian gas field and the Sinian reservoir in Anyue gas field are two typical carbonate gas reservoirs, and their successful development experiences can provide significant references for other similar carbonate gas reservoirs. For Jingbian gas field, it is a lithological-stratigraphic reservoir developed in a westward monocline and multiple rows of nose-fold structures, and is a stable craton basin with simple palaeognomy distribution and stable connectivity, which has complex gas-water distribution. However, for Anyue gas field, it is a lithological-structural reservoir with multiple tectonic high points and multiple fault systems, and is biological dune beach facies under extensional setting with highly differentiated inside of the block in palaeognomy characteristics, which has limited connectivity and tectonic side water is in a local area. The difference of gas reservoir characteristics leads to the diverse development strategies. For these two gas reservoirs, although there are some similar aspects, such as the screen of enrichment areas, the application of irregular well pattern and reservoir stimulation techniques, the criteria of enrichment areas, the well types, and the means of reservoir stimulation are absolutely different. In addition, due to the differences of control reserves and production capacity for these two kinds of reservoirs, the mode of stable production is also different. The effective development of Jingbian gas field can give some references to the future exploitation on the Sinian gas reservoir. Firstly, the sedimentary characteristics should be studied comprehensively. Secondly, the distribution pattern and distribution characteristics of the palaeognomy should be found and determined. Thirdly, the distribution of fracture system in the reservoir should be depicted finely. Finally, dynamic monitoring on the production performance should be strengthened, and the management for this gas field should be improved further. The findings of this study can help for better understanding of the Karst weathering-crust carbonate gas reservoir formation characteristics and the optimal development technologies that should be taken in practice.

Accumulation characteristics of tight sandstone gas reservoirs in the Upper Paleozoic in the Shenfu block of the Ordos Basin

The Shenfu gas field on the eastern margin of the Ordos Basin is one of the key blocks of CNOOC’s land tight sandstone gas field development in recent years. In order to further analyze the physical properties and accumulation and evolution characteristics of the Upper Paleozoic tight sandstone gas reservoirs in the Shenfu block, we characterized of the reservoir pore structure, diagenetic evolution, and natural gas accumulation stages, combined with fluid inclusions, the types of tight sandstone gas reservoirs in the Upper Paleozoic are studied, revealing the main controlling factors for the natural gas accumulation in the study area. Studies have shown that the core porosity of tight sandstone reservoirs in the Upper Paleozoic in the Shenfu block is less than 10%, and the permeability is less than 1mD. Compaction and cementation are the main factors for reservoir tightness. The results of porosity evolution and homogenization temperature of fluid inclusions indicate that the Upper Paleozoic sandstone tightness is formed during the Middle-Late Triassic-Early Jurassic, which is earlier than the Late Jurassic-Early Cretaceous period of large-scale natural gas accumulation.

Facies probability application for gas reservoir characterization

Reservoir characterization through seismic inversion is the principle method in hydrocarbon exploration. Facies probability is an advance method of reservoir characterization which integrates model-based seismic inversion and facies classification to construct a better reservoir modelling. The reservoir modelling is produced from four main steps. First is crossplot analysis to define the relation between acoustic parameter and petrophysics parameter. Second, model-based seismic inversion to produce acoustic impedance volume from seismic data. Third, facies classification which is defined from porosity effective, shale volume and water saturation. Final step is Bayesian Inference Framework to model probability density function (pdf) of each facies. The result of crossplot analysis shows that there is a linear relationship between acoustic impedance and porosity hence the porosity volume can be derived from the model-based inversion result. Facies classification is divided into two categorical zone, pay and non-pay. Pay zone is categorized as a high porosity layer filled with gas. Its parameters fit with Vshale > 0.6, Sw < 0.7 and porosity effective > 0.22. Then estimation is run using Bayesian probability into acoustic impedance volume and porosity volume resulting probability volume of each facies.

A quantitative study of the scale and distribution of tight gas reservoirs in the Sulige gas field, Ordos Basin, northwest China

Gas and water distribution is discontinuous in tight gas reservoirs, and a quantitative understanding of the factors controlling the scale and distribution of effective reservoirs is important for natural gas exploration. We used geological and geophysical explanation results, dynamic and static well test data, interference well test and static pressure test to calculate the distribution and characteristics of tight gas reservoirs in the H8 Member of the Shihezi Formation, Sulige gas field, Ordos Basin, northwest China. Our evaluation system examines the scale, physical properties, gas-bearing properties, and other reservoir features, and results in classification of effective reservoirs into types I, II, and III that differ greatly in size, porosity, permeability, and saturation. The average thickness, length, and width of type I effective reservoirs are 2.89, 808, and 598 m, respectively, and the porosity is > 10.0%, permeability is > 10 × 10−3 µm2, and average gas saturation is > 60%. Compared with conventional gas reservoirs, tight gas effective reservoirs are small-scale and have low gas saturation. Our results show that the scale of the sedimentary system controls the size of the dominant microfacies in which tight gas effective reservoirs form. The presence of different types of interbeds hinders the connectivity of effective sand body reservoirs. The gas source conditions and pore characteristics of the reservoirs control sand body gas filling and reservoir formation. The physical properties and structural nature of the reservoirs control gas-water separation and the gas contents of effective reservoirs. The results are beneficial for the understanding of gas reservoir distribution in the whole Ordos Basin and other similar basins worldwide.

Improving Tight Gas Recovery from Multi-pressure System During Commingled Production: An Experimental Investigation

Commingled production has been widely used as an efficient production method in gas field. However, the interlayer interference of gas flow seriously restricts the improvement of gas recovery. Presently, there are several investigations on commingled production characteristics of multi-pressure system gas reservoirs, but no corresponding improved production methods have been proposed. In this study, commingled production characteristics were studied by conducting simultaneous production (simultaneously opening all gas layers for production) simulation experiments. Subsequently, the mechanism of eliminating interlayer interference was revealed by conducting progressive production (progressively opening each gas layer for production) simulation experiments. Then, the effect of interlayer pressure difference on the gas recovery was studied to evaluate the improvement effect of gas recovery. Finally, the effects of initial temperature and pressure on gas recovery were explored to judge the applicability of the progressive production. All experiments were conducted with full-diameter cores of tight sandstone under conditions of temperature, pressure and gas–water saturation similar to those of the actual reservoirs. Experimental results showed that the gas produced by the high-pressure layer may flow back to the low-pressure layer through the interconnected pipeline at outlet end, thereby inhibiting the production capacity of the low-pressure layer and the gas recovery during commingled production. The progressive production method effectively avoids the occurrence of backflow, reduces the effect of interlayer interference, balances the production contribution ratio of different layers and improves the total gas production and recovery efficiency. The progressive production can improve the gas recovery of all gas layers; however, the improvement effect on the low-pressure layer is much better than on the high-pressure layer. The gas recovery from the low-pressure layer to the high-pressure layer increased by 2.62%, 2.23%, 1.41% and 1.23%, respectively. The increase in interlayer pressure difference can intensify interlayer interference and reduce the gas recovery of both simultaneous and progressive production. However, the greater the interlayer pressure difference (2, 3 and 4 MPa), the better the improvement effect of the progressive production in gas recovery (2.04%, 2.66% and 3.61%). The progressive production is effective for multi-pressure system with different initial temperatures and pressures.

Characterization and development of marine natural gas hydrate reservoirs in clayey-silt sediments: A review and discussion

As a promising substitute for conventional fossil fuels with huge reserves, clayey-silt natural gas hydrate has been proved to be widely distributed in the continental margins of the marine environment. Characterization and development of this kind of natural gas hydrate reservoirs face unique challenges, compared with that of natural gas hydrate in marine sandy sediments. This review summarizes the basic methods for natural gas hydrate reservoir characterization and development, and discusses the applicability of these methods in marine clayey-silt natural gas hydrate reservoirs. Feasibilities of classical oil and gas reservoir characterization methods and models applied to hydrate-bearing stratum remain elusive, let alone clayey-silt hydrate deposits. Current natural gas hydrate development methods are restricted by low gas productivity, potential geomechanical instability, and extremely high costs. Economically feasible technologies considering the influences of geotechnical issues are needed for the commercialization of natural gas hydrate contained in clayey-silt sediment. Cited as : Li, Y., Liu, L., Jin, Y., Wu, N. Characterization and development of natural gas hydrate in marine clayey-silt reservoirs: A review and discussion. Advances in Geo-Energy Research, 2021, 5(1): 75-86, doi: 10.46690/ager.2021.01.08

Simultaneous inversion for S-wave velocity and density from the SV-SV wave

Knowledge of the S-wave velocity ([Formula: see text]) and density ([Formula: see text]) is essential for oil and gas reservoir detection and characterization. However, reliable recovery of both parameters, especially density, from the reflected PP-wave data is a difficult issue because this inverse problem is highly ill-conditioned. The reflected SV-SV wave is easier to process than the PS-wave, and it can provide better estimates of [Formula: see text] and [Formula: see text] than the PP-wave because it is more sensitive to these parameters than the PP-wave. I have developed a simultaneous inversion for [Formula: see text] and [Formula: see text] based on a modified approximation of the SV-SV wave reflection coefficient. The modified equation includes only two parameters (natural logarithms of [Formula: see text] and [Formula: see text]) to be inverted, and it has high accuracy even at large incident angles and for strong impedance contrasts. I find that simultaneous inversion based on the modified approximation is well-posed when using data of small-to-moderate incident angle (20o–30o) and that the misfit function can be easily regularized. The new simultaneous inversion method is applied to an SV-SV wave prestack data set acquired from a 2D nine-component survey. The field data example demonstrates that the new method can recover stable and high-resolution density and S-wave velocity information, which can be used to investigate rock mineral composition, porosity, and fluid content.

New Understanding of Bar Top Hollows in Dryland Sandy Braided Rivers from Outcrops with Unmanned Aerial Vehicle and Ground Penetrating Radar Surveys

Bar top hollows (BTHs) are morphological elements recognized in modern braided rivers; however, information regarding their depositional features and types of filling units in ancient strata is unclear. This is an important reason behind why it is difficult to identify BTH units in subsurface reservoirs. A Middle Jurassic dryland sandy braided river outcrop in northwestern China is characterized in this study through the application of an unmanned aerial vehicle (UAV) surveying and mapping, and ground penetrating radar (GPR). A workflow of UAV data processing has been established, and a 3D digital outcrop model has been built. By observation and measurement of the outcrop model and GPR profiles, two types of BTH filled units were found: (a) sandstone-filled, and (b) mudstone-filled hollows. Both of these units were located between two adjacent bar units in an area that is limited to a compound bar, and were developed in the upper part of a braided bar depositional sequence. The ellipse-shaped, sandstone-filled unit measures 10 m × 27 m in map view and reaches a maximum thickness of 5 m. The transversal cross-section across the BTHs displays a concave upward basal surface, while the angle of the inclined structures infilling the BTHs decreases up-section. The GPR data show that, in the longitudinal profile, the basal surface is relatively flat, and low-angle, inclined layers can be observed in the lower- and middle part of the sandstone-filled BTHs. In contrast, no obvious depositional structures were observed in the mudstone-filled BTH in outcrop. The new understanding of BTH has a wide application, including the optimization of CO2 storage sites, fresh water aquifers exploration, and oil and gas reservoir characterization.