Tight Sandstone Gas Reservoirs Research Articles

Accumulation and Distribution of Natural Gas Reservoir in Volcanic Active Area: A Case Study of the Cretaceous Yingcheng Formation in the Dehui Fault Depression, Songliao Basin, NE China

Tight gas sandstone and volcanic gas reservoirs have received global attention in the energy arena for further exploration and exploitation attempts. Considering the Yingcheng Formation of Dehui fault depression in the Songliao Basin as an example, this study focused on the accumulation and distribution of natural gas reservoirs in volcanic area in a fault depression basin. Volcanic activities occurred in the Yingcheng Formation, which is distributed centrally in the northwest of the study area. During the sedimentation of the Yingcheng Formation, fan-delta, lacustrine, and nearshore subaqueous fan facies were deposited. The source rocks of the Yingcheng Formation have high abundance of organic matter mainly in type III at high-overmature stages, indicating favorable conditions for gas production. The porosity of volcanic reservoir is 3.0%-14.8%, the permeability is 0.0004 mD-2.52 mD, and the pore types are mainly secondary dissolved pores and fractures. Besides, the porosity of the tight sandstone reservoir is 0.5%-11.2%, and the permeability is 0.0008 mD-3.17 mD. The pore types are mainly interparticle pores, with a small proportion of intraparticle pores and microfractures. The intrusion of late volcanic magma provided sufficient heat for the thermal maturity progression of organic matter in Yingcheng Formation and promoted the generation of natural gas in large quantities. Volcanic rocks formed at the early and middle stages of volcanic activities occupied the sedimentary space and hindered the development of sedimentary sand bodies to a certain extent. However, volcanic rocks can become the seal to promote the formation of tight sandstone gas traps. Comparing tight sandstone reservoirs with volcanic ones, the latter are less affected by compaction; thus, their petrophysical properties do not vary much with depth, showing more homogeneous characteristics. The pyroclastic rocks influenced by volcanic activity and the secondary pores formed by dissolution in the later stages also provide reservoir space for gas accumulation. Ultimately, the tight sandstone and volcanic rocks in the study area form a complex gas reservoir system, which can become a reference for exploration and exploitation of natural gas in other petroliferous fault depressions that are affected by volcanisms.

Productivity Influence Factors of Tight Sandstone Gas Reservoir with Water Produced

Finding ways to accelerate the effective development of tight sandstone gas reservoirs holds great strategic importance in regard to the improvement of consumption pattern of world energy. The pores and throats of the tight sandstone gas reservoir are small with abundant interstitial materials. Moreover, the mechanism of gas flow is highly complex. This paper is based on the research of a typical tight sandstone gas reservoir in Changqing Oilfield. A strong stress sensitivity in tight sandstone gas reservoir is indicated by the results, and it would be strengthened with the water production; at the same time, a rise to start-up pressure gradient would be given by the water producing process. With the increase in driving pressure gradient, the relative permeability of water also increases gradually, while that of gas decreases instead. Following these results, a model of gas-water two-phase flow has been built, keeping stress sensitivity, start-up pressure gradient, and the change of relative permeability in consideration. It is illustrated by the results of calculations that there is a reduction in the duration of plateau production period and the gas recovery factor during this period if the stress sensitivity and start-up pressure gradient are considered. In contrast to the start-up pressure gradient, stress sensitivity holds a greater influence on gas well productivity.

Study on unsteady seepage characteristics and production decline of tight channel sandstone gas reservoirs

Tight channel sandstone gas reservoirs are mainly characterized by low porosity and permeability to ultra-low porosity and permeability, strong heterogeneity, and slow energy supply rate in the later stage, resulting in small gas well control reserves, and fast decline rate of gas well pressure and production. Therefore, it is urgent to carry out targeted research on production decline. In this paper, from the perspective of percolation mechanics, a mathematical model of low-velocity non-Darcy unstable percolation in tight channel sandstone gas reservoir is established, a diagram of the relationship between non-Darcy effect, flow boundary characteristics, and dynamic bottom-hole flow is established, and the dynamic influencing factors of bottom hole flow are analyzed. From a seepage mechanics point of view, this paper establishes a tight sandstone gas reservoir river unstable low-speed non-darcy seepage flow mathematical model of non-darcy effect and flow boundary characteristics and the relationship between the bottom hole flow dynamic chart and analysis of bottom hole flow dynamic influence factors, research shows that start-up pressure gradient, skin factor, the closed boundary of tight sandstone gas reservoir river bottom hole flow dynamic effect is bigger, The research content of this paper has certain guiding significance for realizing the effective development of tight channel sandstone gas reservoir.

Study on unsteady seepage characteristics and EUR evaluation methods of tight channel sandstone gas reservoirs

Tight channel sandstone gas reservoirs have the characteristics of strong heterogeneity, low porosity and permeability, and slow formation energy supply in the later stage of mining. In the process of gas well development, the initial production deceleration rate is fast, the later production deceleration rate is slow, and the EUR prediction result is large in error. In response to the above problems, this paper starts from the perspective of seepage mechanics, establishes a EUR evaluation mathematical model, derives the staged fractured horizontal well pressure response model and productivity model, predicts future production performance based on the production instability method, and uses Topaze The production analysis software adopts the method of production instability analysis to simulate and analyze the single well controlled reserves at different production times in stages, which further confirms the change process. The research results of this paper have certain guiding significance for predicting and analyzing single-well EUR.

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.

The practice and effect analysis of gas production with plunger drainage in tight sandstone gas reservoirs: Taking Bajiaochang Xusi gas reservoir as an example

The Bajiaochang Xusi gas reservoir has the characteristics of low porosity, low permeability and high water saturation, and is a typical tight sandstone gas reservoir. Gas wells are generally low in productivity and generally produce water. Gas wells carry fluid smoothly under the conditions of large pressure difference in the initial stage of production. However, as the formation pressure drops, the ability of gas wells to carry fluid weakens. Some wells can only maintain production through indirection. The Tibetan production organization has brought difficulties. For gas wells with low production, low pressure, high water content, and easy accumulation of liquids, Xusi gas reservoirs have carried out drainage gas recovery technology tests such as bubble drainage and plunger gas lift, and comprehensively selected plunger gas lift as the main drainage of the block. Gas production process measures, and promoted and applied. At present, the plunger gas lift drainage gas production technology has been implemented in 13 wells, accounting for 48% of the total wells, and the measured production accounted for 31% of the total production. It is already in the stage of wide application. Through this measure, the stable liquid carrying of water-producing gas wells was realized, the productivity of gas wells was maintained, and the production decline was delayed. The production decline was controlled at about 6%, and good application effects were achieved.

Optimization of construction parameters for fractured horizontal wells in the southern block of eastern Sulige gas field.

Sulige gas field is a typical tight sandstone gas reservoir. Single well stimulation is an effective means of late fracturing. Because of the complex geological conditions in the Sulige area, there is little research on fracture parameter design of fractured horizontal wells. Based on the geological and engineering parameters of fractured horizontal wells in the block, the numerical simulation method is used to analyze the block. It is clear that the main controlling factors affecting the fracturing effect in the well area are fracture conductivity, fracture length, and fracture cluster number, and the optimal scheme to improve the single well production is proposed.

Experimental study on reasonable production allocation of tight sandstone gas reservoir

Due to the characteristics of poor physical property, low natural productivity, and rapid production decline of tight sandstone gas reservoir[1]. Therefore, it is usually necessary to optimize the working system of gas Wells after fracturing in tight gas reservoirs and determine the length of stable production period to ensure the large accumulated gas volume. In this paper, through the reasonable production allocation experiment on tight sandstone reservoir cores, the comparison diagram of instantaneous flow and cumulative gas volume at the end of stable production at different stable production rates is established, and the optimization experimental results of reasonable production allocation working system of gas Wells are obtained to determine the optimal stable production rate interval. Understanding and mastering the stable production capacity and reasonable production allocation of gas Wells in tight gas reservoirs provides the corresponding basis for formulating reasonable development measures of gas fields, and provides quantitative analysis means for optimizing the production allocation of gas Wells[2].

Optimization of Key Parameters of Tight Cut Fracturing Cracks for Horizontal Well Development of Tight Sandstone Gas Reservoirs

The permeability of dense sandstone gas deposit substation is very low, and it is often developed by horizontal well-tight cutting fracturing. The pressure crack network determines the production capacity of the gas well, so the optimization of the seam mesh parameters is the key problem in the efficient development of dense sandstone gas deposit. In order to solve the problem of multi-parameter comprehensive optimization of fracking horizontal wells, based on the principle of unstable seepage, a model for predicting the yield of fracking gas storage horizontal wells considering crack interference is established, and different crack conductivity, crack length, different crack patterns, crack spacing and number of crack clusters are designed in the model to simulate production, and the optimal fracking crack parameters are compared. Using numerical simulation method to analyze the main control factors of horizontal well fracturing effect, obtain the optimal parameters of fracking cracks, and provide ideas and reference for horizontal well fracturing construction in dense sandstone gas storage sites, which has certain theoretical guidance significance.

Analysis of Microscopic Main Controlling Factors for Occurrence of Movable Fluid in Tight Sandstone Gas Reservoirs Based on Improved Grey Correlation Theory

Tight sandstone reservoirs have the characteristics of poor physical properties, fine pore throats, and strong microheterogeneity compared with conventional reservoirs, which results in complicated movable fluid occurrence laws and difficult mining. Taking the tight sandstone gas reservoir of He 8 formation in Sulige gas field as an example, based on physical property test analysis, constant velocity mercury injection, and nuclear magnetic resonance experiments, an optimized gray correlation calculation model is established by improved gray correlation theory, which quantitatively characterizes the influence of microscopic pore structure parameters of different types of tight sandstone gas reservoirs on the occurrence of movable fluids, and the main controlling microgeological factors for the occurrence of movable fluid in tight sandstone gas reservoirs with close/similar physical properties are selected. The results show that the occurrence of movable fluid in Type I reservoirs is mainly affected by the effective pore-throat radius ratio, the saturation of mercury in the total throat, and the effective pore radius, and the occurrence of movable fluid in Type II reservoirs is mainly affected by the effective throat radius per unit volume and total throat mercury saturation and mainstream throat radius. Moreover, the occurrence state of movable fluids in Type II reservoirs is controlled by the throat radius stronger than that of Type I reservoirs. It has important guiding significance for the efficient development of tight sandstone gas reservoirs.

Research progress in damage assessment methods for tight sandstone gas reservoirs

In the process of oil and gas development, the perfect reservoir damage evaluation method is an important condition to realize the economical and efficient development of the reservoir. At present, great progress has been made in the exploration of tight oil and gas. However, due to the characteristics of low porosity, low permeability and low water saturation of tight sandstone gas reservoirs, conventional reservoir damage evaluation methods are not applicable to it, and no systematic evaluation method has been formed yet. The damage evaluation methods of tight sandstone gas reservoirs mainly include the steady-state method and the unsteady-state method. The steady-state method is mainly the high temperature and high back pressure method, while the unsteady-state methods are the pressure attenuation method and the pressure transmission method which are widely applicable. Visualization technology, microfluidic technology, flow rate evaluation method and recovery evaluation method are the new methods to evaluate reservoir damage, which are in the further research. This paper summarizes the research progress of reservoir damage evaluation methods for tight sandstone gas reservoirs, analyzes the main evaluation methods, experimental equipment and improvement measures, and points out the problems that need to be paid attention to and solved, in order to provide reference for efficient and accurate evaluation of reservoir damage in tight sandstone gas reservoirs.

Practice of high-intensity volume fracturing in the Shaximiao Formation tight sandstone gas reservoirs of the Qiulin Block, central Sichuan Basin

In order to solve the difficulties in the volume fracturing stimulation of Middle Jurassic Shaximiao Formation tight sandstone reservoirs in the Qiulin Block of Central Sichuan Basin and explore the adaptability of high-intensity volume fracturing technology, we selected the outcrop samples of Shaximiao Formation tight sandstone in the Qiulin Block to carry out the physical simulation experiment of true triaxial hydraulic fracturing. On this basis, horizontal well cluster perforation was optimally designed by using the production prediction model of staged multi-cluster fracturing horizontal wells. Then, based on the liquid control and proppant increase mode, three rounds of pilot tests were carried out on the tight sandstone reservoirs in this area. And the following research results were obtained. First, natural fractures in the Shaximiao Formation tight sandstone reservoir of the Qiulin Block are undeveloped, and hydraulic fractures are morphologically dominated by symmetric double-wing fractures, so complex fracture networks can be hardly formed. In addition, the reservoir is of medium to strong water sensitivity, so conventional volume fracturing is not adaptive to the reservoir stimulation in this block. Second, the connotation of high-intensity volume fracturing technology is to carry out multi-cluster perforation in each section to form multiple independent double-wing fractures and to implement the proppant injection mode of liquid control and proppant increase to reduce the inflow fluid while ensuring the high-intensity proppant injection, so as to reduce the damage of inflow fluid to the formation. Third, there are 10 fracturing sections in Well Qiulin 207-5-H2, with 7–12 clusters in each section, and the displacement is in the range of 16–18 m3/min. According to the fluid control and proppant increase mode, 12146 m3 slick water and 4170 t proppant are injected in total. The tested production rate and absolute open flow of natural gas after the fracturing are up to 83.88 × 104 m3/d and 214.05 × 104 m3/d, respectively. Fourth, with the decrease of cluster spacing, the cumulative gas production increases gradually, but when the cluster spacing is less than 15 m, the increase amplitude of cumulative gas production decreases. Fifth, when the proppant injection intensity is lower than 6 t/m, the tested gas production per kilometer of stimulated section in a horizontal well overall presents an increasing trend with the increase of proppant injection intensity. When the proppant injection intensity is higher than 6 t/m, however, the tested gas production per kilometer of stimulated section does not increase significantly with the increase of proppant injection intensity. Sixth, as the included angle between the borehole trajectory and the direction of maximum horizontal principal stress increases, the tested gas production per kilometer of stimulated section overall presents an increasing trend. When the hydraulic fracture is nearly perpendicular to the borehole, the effective drainage area is the largest and the tested gas production per kilometer of stimulated section is also the highest. In conclusion, the fracturing mode of high production well has a borehole trajectory of large included angle, perforation cluster spacing of 10 m or so, proppant injection intensity of 5 t/m and large-displacement slick water + continuous injection of combined particle size proppant.

Micro-occurrence of formation water in tight sandstone gas reservoirs of low hydrocarbon generating intensity: Case study of northern Tianhuan Depression in the Ordos Basin, NW China

A series of experimental techniques which contain casting thin slice observation, field emission scanning electron microscopy, high-pressure mercury injection, constant-velocity mercury injection, and NMR(nuclear magnetic resonance) were used to study the throat microstructure and microscopic occurrence of formation water in the Upper Paleozoic tight sandstone gas reservoir in northern Tianhuan Depression, Ordos Basin. The results show that intragranular dissolution pores, intercrystalline pores, and residual intergranular pores represent 33 %, 31 %, and 16 % of the pore types in the reservoir of the He8-Shan1 members in the northern Tianhuan Depression, respectively. Pore radii range from 80 μm to 300 μm, with an average of 154.18 μm, while throat radii range from 0.01 μm to 1.60 μm, with an average of 0.55 μm. Micron pores and nano throats control the seepage ability of the reservoirs, and the throat radius serves as the controlling factor. Formation water has four microscopic occurrences: bound water, capillary water, free water, and adsorbed water. At low charging pressure, a mixture of gas and water was found in the intergranular pores and dissolution pores controlled by macro throats, with a high gas content and existent free water; a small amount of membrane adsorption water was observed at high charging pressure. However, in the intergranular pores and dissolution pores controlled by medium-small throats, the mixture of gas and water at low charging pressure presents a low gas content and a large amount of capillary water, while at high charging pressure, the mixture of gas and water or pure gas presents a high gas content and a small amount of capillary water. Pure water controlled by tiny throats, on the other hand, was found at low charging pressure in the intergranular pores, whereas gas and water mixture was found at high charging pressure, but the gas content is low and bound water appears. In the intergranular micropores, pure water, which is bound water, is the primary composition at both low and high charging pressure. The throat radius cut-offs of the four kinds of formation water are 0.10 μm, 0.26 μm, and 0.28 μm, the permeability cutoffs are 0.21 × 10−3 μm2, 0.51 × 10−3 μm2, and 0.55 × 10−3 μm2, and the porosity cutoffs are 5.86 %, 7.99 %, and 8.18 %, respectively. The starting pressure gradient and throats less than 0.10 μm are controlling factors on the micro-occurrence and residual water saturation of formation water. As the amount of gas driving water increases in the natural gas accumulation process, the percentage of formation water controlled by large throats gradually decreases. Free water makes up 50 % of the research area, capillary water makes up 18 %, bound water compensates 30 %, adsorbed water is 2 %, and residual water saturation is about 32 %.

Development of a new model for prediction of cementation factor in tight gas sandstones based on electrical rock typing

Evaluation of tight gas sandstone (TGS) reservoirs and estimation of their reserves are associated with significant uncertainties. Indeed, estimation of electrical properties, such as cementation factor (m), is one of the main challenges in TGS characterization. Well known Archie's formula is applied to determine water saturation and therefore hydrocarbon saturation. Diagenetic processes and presence of fractures and slot-like pore throats in TGS reservoirs cause that m varies in a wide range. Furthermore, correlations which have been developed for a specific formation, generally cannot be applied for prediction of cementation factor in other formations. Besides, several studies of cementation factor in conventional reservoirs show that classification of the reservoir rocks based on a common parameter may result in an appropriate estimation of m. In this paper, electrical efficiency (ηe) was presented as a basis for classification of rock samples into distinct electrical rock types. Indeed, all rock samples with similar electrical efficiency lie on the same straight line with slope of (−1) and intercept of 1ηe in the log-log plot of formation resistivity factor (F) versus porosity (φ). Moreover, in this study a new theoretical equation was developed for prediction of m versus porosity. This equation shows that for each electrical rock type, m versus 1lnφ has a linear trend and its intercept is one. To verify this electrical rock typing approach, a large dataset from Byrnes' et al. work related to Mesaverde tight gas sandstone was used. These samples were classified into five different groups based on the proposed technique of electrical rock typing. Additionally, results revealed that values of cementation factor of each electrical rock type properly satisfy in the new established linear equation of m versus 1lnφ.

Production Data Analysis and Practical Applications in the Sulige Tight Gas Reservoir, Ordos Basin, China

Successful exploitation of tight sandstone gas is one of the important means to ensure the “increasing reserves and production” of the oil and gas initiative and also one of the important ways to ensure national energy security. To further improve the accuracy of historical matching of field data such as gas production and bottom-hole pressure during the production process of this type of gas reservoir, in this study, a new expression of wellbore pressure for the uniform flow of vertical fractured wells in Laplace space based on the point sink function model of vertical fractures in tight sandstone gas reservoirs is constructed. This innovation is based on a typical production data analysis plot of the Blasingame type that uses the numerical inversion decoupling mathematical equation. After analyzing the pressure and pressure derivative characteristics of each flow stage in the typical curves, a new technique of type-curve matching was proposed. In order to verify the correctness of the model and the application value of the field, based on the previous production data of Sulige Gas Field in China, a new set of production data diagnostic chart of tight sandstone gas reservoir was formed. A case analysis showed that the application of the production data analysis method and data diagnosis plot in the field accurately evaluated the development effect of the tight sandstone gas reservoirs, clarified the scale of effective sand bodies, and provided technical support for optimizing and improving the well pattern and realizing the efficient development of gas fields.

Estimation of the Pore Microstructure of Tight-Gas Sandstone Reservoirs with Seismic Data

Tight-sandstone reservoirs have a complex pore structure with microcracks and intergranular pores, which have a significant impact on the seismic properties. We have performed ultrasonic measurements at different confining pressures for 15 tight-gas sandstone samples of the Xujiahe formation in Western Sichuan Basin, and have available well-log and seismic data of this area. The aim of this work is to estimate the porosity and crack properties for variable pressure conditions. The EIAS (equivalent inclusion-average stress) model is adopted to compute the high- and low-frequency bulk and shear moduli as a function of crack aspect ratio and (soft) and (stiff) porosities. Then, we use the EIAS-Zener anelastic model to obtain the wave properties as a function of frequency, and compare results with those of the constant Q (Kjartansson) one for verification of the robustness of the approach. The corresponding P-wave impedance, density and phase velocity ratio (VP/VS) are computed in order to built 3D rock‐physics templates (RPTs) at the ultrasonic, well-log and seismic frequency bands. The methodology is applied to a survey line crossing two wells, which together with the laboratory experiments, provide calibration suitable data. The estimated stiff porosity and crack porosity and density are consistent with the available data and actual production records, indicating that 3D RPTs provide a useful interpretation tool in seismic exploration and prospect evaluation.

Evolution Mechanism of Differential Diagenesis Combination and Its Effect on the Reservoir Quality in the Tight Sandstone: A Case from the Lower Shihezi Formation in the Hangjinqi Area of Ordos Basin, China

Abstract The physical property heterogeneity of tight sandstones was mainly caused by complex alteration of various diagenesis combinations during burial process. However, diagenetic evolution of different diagenesis combinations which generally result in the strong difference and heterogeneity of physical property and pore structure is rarely well understood. The Middle Permian lower Shihezi Formation is one of the most important tight gas sandstone reservoirs in the Hangjinqi area of Ordos Basin, China. The reservoir heterogeneity of lower Shihezi Formation, which was caused by the differential diagenesis combination, is crucial to efficient exploration and development. Evolution mechanism of differential diagenesis combination and its effect on the reservoir quality in the tight lower Shihezi Formation sandstone in the Hangjinqi area of Ordos Basin was investigated by means of thin-section description, cathodoluminescence (CL) imaging, X-ray diffraction (XRD), scanning electron microscopy (SEM), and homogenization temperature of fluid inclusions. The lower Shihezi Formation sandstones can be divided into four diagenesis combination types according to the reservoir characteristics and diagenetic relationship. The main diagenetic sequence was mechanical compaction-chlorite rim-early pore-filling calcite cementation-dissolution-authigenic kaolinite-quartz cementation-late calcite cementation. Differential diagenesis combination was mainly controlled by the petrological characteristics, microfacies, and fault. Low content of rock fragment and high content of detrital quartz were beneficial to the compaction resistance and cementation. The moderate content of pore-filling calcite was conducive to pore space protection and feldspar dissolution. The faults control dissolution and differential diagenesis combination by influencing the migration of acid fluids. Moderate compaction-moderate cementation-moderate dissolution type (BBB type) and weak compaction-moderate cementation-strong dissolution type (CBA type) were in favour of high-quality reservoir development.

Relation of Heterogeneity and Gas-Bearing Capacity of Tight Sandstone: A Case Study of the Upper Paleozoic Tight Gas Sandstone Reservoir in the Southeast of the Ordos Basin.

Compared to conventional reservoirs, only a few studies were carried out on the heterogeneity of unconventional tight sandstone reservoirs. This paper focuses on the Upper Paleozoic tight gas sandstone reservoir in the southeast of the Ordos Basin. The reservoir heterogeneity is studied through thin section and scanning electron microscope observations, cathode luminescence, mercury intrusion, and logging data analysis. The results show that the dissolution pore and microfracture is the dominant pathway for the migration of natural gas. The distribution of gas and water within the sand body is affected by the rhythmic change of sandstone, and this rhythmicity is variable with the changing of particle size. It shows “water wrapping gas” for the positive rhythm, “gas wrapping water” for the reverse rhythm, and both of these features for the compound rhythm. Interlayers act as a cap rock or carrier bed on gas distribution. Along with the variation of breakthrough pressure of the interlayer and saturation pressure of the reservoir, the single sand body shows different distribution features of gas and water. The vertical differentiation of natural gas is caused by the barrier layer, and the more barrier layers exist, the worse the capacity of the reservoir to store natural gas. However, the existence of the barrier layer will make the reservoir close to the source area to be the favorable zone for oil and gas accumulation. In this study, the relationship between heterogeneity and gas as well as water distribution of tight sandstone is identified, which can provide guidance to the exploration and exploitation of tight gas in the future.

Characterization of Gas Saturation in Tight-Sandstone Reservoirs with Rock-Physics Templates Based on Seismic Q

Tight-sandstone gas reservoirs have low porosity and permeability, dissimilar pore types, and generally high clay content. Partial saturation leads to local fluid flow induced by seismic waves, resulting in velocity dispersion and attenuation, and this is the reason why the dissipation factor (Q−1) (inverse quality factor) is highly sensitive to fluid saturation. A relation between Q and saturation can be based on the self-consistent approximation and poroelasticity theory, to build, in principle, a two-dimensional (2D) rock-physics template. However, there is an ambiguity in the process of estimation because one value of Q may correspond to two saturations. Thus, this paper addresses this limitation. Moreover, a well-log in the Sichuan Basin and reported experimental data show that these reservoirs may have a high clay content, which affects the estimation. To take into account this factor, the hydration effect of clay is considered in the framework of the double double-porosity theory of wave propagation. Ultrasonic measurements were performed on a tight sandstone and the spectral-ratio method was used to estimate Q. Then, three-dimensional (3D) rock-physics templates are built by introducing the phase velocity ratio (VP/VS), clay content, and seismic Q estimated with an improved frequency-shift method. The template is calibrated and tested with ultrasonic, well-log, and seismic data and applied to estimate reservoir porosity, clay content, and gas saturation on 2D and 3D seismic data.

The enrichment law of tight sandstone gas in member 2 of Xujiahe in Yingshan gas field, Sichuan Basin

The enrichment law of desserts in Xujiahe formation of Sichuan Basin has become the core problem of tight sandstone gas reservoir. In view of this problem, taking the member 2 of Xujiahe Formation in Yingshan area of Sichuan Basin as an example, the author analyzes the main factors of enrichment of natural gas through the analysis of the basic geological features of sedimentary environment, reservoir, hydrocarbon source, structure and reservoir formation, and then discusses enrichment mode of natural gas. The results show that the reservoir forming conditions of member 2 in Yingshan area are superior, and the widely covered source rocks are developed, and the source rocks have good hydrocarbon generation potential. The sand bodies in the delta front with thick layers are deposited in member 2 of Xujiahe, which is distributed in large area, which lays the foundation for the development of high-quality reservoirs. The reservoir space types are various, mainly mainly including primary intergranular pores, dissolution pores and micro fractures, and the reservoir has good physical properties. The accumulation of natural gas in Yingshan structure is the result of coupling of the following factors: the development of high-quality reservoir controls the distribution of natural gas; the structural background is conducive to the enrichment of natural gas; the good matching relationship between faults and traps controls the differential accumulation of natural gas in the reservoir.