Tight Sandstone Formation Research Articles

Diagenesis and controlling factors of Oligocene Huagang Formation tight sandstone reservoir in the south of Xihu sag, the East China Sea Shelf Basin

Considerable amounts of efforts have been made in search of depositional sand quality and diagenetic processes on the quality of low-permeability and tight reservoirs mainly due to the realization that these multiple factors exert profound controls on reservoir quality. This study evaluated the role played by original components and diagenetic processes on reservoir quality evolution of Oligocene Huagang Formation reservoir in the south of Xihu sag from braided river delta (H3, H4 and H5) to meandering river delta (H6 and H7). By a multi-disciplinary approach of thin section identification, scanning electron microscopy, grain size analysis, mineral phase analysis, and X-ray diffraction, the petrological characteristics, grain structure, and diagenesis of five of the layers (H3, H4, H5, H6, and H7) of Huagang Formation in the Western slope belt (WSB), the Western sag (WS) and the Central uplift belt (CUB) were studied. It was determined that the reservoirs are mainly composed of fine-medium sandstone (94.1%) and feldspathic lithic quartz sandstone (Q65.6F15.8L18.6). The E3H reservoirs in WSB and CUB Ⅲ structural belt are of conventional types with an average porosity of 13.2% and permeability of 30 × 103 μm2, and reservoirs in WS, CUB Ⅰ and CUB Ⅱ are mainly tight sand with an average porosity of 7.8% and permeability of 2.9 × 103 μm2. Furthermore, quantified characterization of diagenetic factors on porosity was revealed by multiple regression analysis to find out the depositional and diagenetic controls on reservoir quality. The effect of sorting, grain size, rigid lithic fragment, argillaceous content, compaction and feldspar dissolution have been identified as main contributing factors for reservoir quality evolution of E3h sandstones, notably post-depositional processes on the deep (3500–4500 m) and ultra-deep (>4500 m) tight sandstone reservoirs (DUDTSR) with high degree of diagenetic stage. Therefore, a better understanding of diagenesis will provide an efficient approach for evaluation and prediction of the DUDTSR.

Ionic liquids as completion fluids to mitigate formation damage

Formation damage can occur in any phase of oil and gas operation from drilling, completion, or stimulation. Fluids used to drill, complete, and fracture the formation may invade and damage the formation. These fluids may interact with clays present in the formation and adversely affect the flow performance. The change in flow performance could occur due to flow restriction or decrease in permeability, change in relative permeability, or unintended flow restriction during the specific operation. In this work, ionic liquids are proposed as clay swelling additives in completion fluid to overcome the formation damage problem. Imidazolium-based ionic liquids and three different salts are tested with 0.5 wt % and 3 wt % concentration, respectively, on tight sandstone formation containing high clay contents. Completion fluids prepared using ionic liquids resulted in complete stabilization of clays and therefore nearly maintain the in-situ permeability of tight sandstone. The completion fluids are prepared in deionized water for experimental consistency. Coreflooding experiments were performed on Scioto sandstone core samples containing an average porosity and permeability of 16.9% and 0.72 mD., respectively. Cores were saturated with completion fluids based on salts such as calcium chloride (CaCl2), magnesium chloride (MgCl2), and ammonium chloride (NH4Cl) and with Imidazolium-based ionic liquids before the coreflooding experiments. These coreflood experiments involve a preflush with the prepared completion fluid and post-flood with deionized water. Moreover, Nuclear Magnetic Resonance (NMR) tests were performed on all samples before and after coreflood to estimate the change in porosity and pore size distributions of the rock samples. Results showed that the porosity and permeability loss were significantly large in cores flooded with CaCl2 and NH4Cl salts solution when flooded with water. MgCl2 salt solution showed exceptionally stable porosity and permeability compared to other completion fluids. Furthermore, the results of ionic liquid-based completion fluids showed no significant loss in porosity and permeability when flooded with water. Therefore, the proposed ionic liquid-based completion fluids can be used for well-completion operation without any formation damage.

Coupling relationship between reservoir densification and hydrocarbon emplacement in the Jurassic Badaowan Formation sandstone reservoirs of the southern Junggar Basin, China

Understanding the interrelationship between diagenesis and hydrocarbon emplacement is crucially important for investigating tight sandstone reservoir‐forming processes. In this paper, efforts were made to elucidate this interrelationship in the Jurassic Badaowan Formation tight sandstone reservoirs of the southern margin of the Junggar Basin (SJB), China. Four lithofacies were clarified, including quartz cemented‐dissolution facies (QCDF), carbonate cemented facies (CCF), authigenic clay mineral facies (ACMF), and matrix‐caused tightly compacted facies (MCTF). Weak hydrocarbon migration forces and poor hydrocarbon preservation conditions were identified to be the main reasons for the limited hydrocarbon accumulation scale. The reservoir densification process, mostly before 100 Ma, was associated with four aspects, including the high matrix content, the intensive carbonate cementation, the limited dissolution and alteration, and the development of authigenic clay minerals. Hydrocarbons in the Badaowan Formation reservoir were demonstrated to be emplaced after reservoir densification. Overpressure resulting from hydrocarbon expulsion and tectonic compression should have acted as the main driver for hydrocarbon migration. Particularly, the tight sandstone in the Qigu anticline was charged with overpressurized hydrocarbons sourced from the middle‐lower Jurassic source rocks at the footwall of the Qigu north fault since the early Jurassic. The tectonic compression in the late Neogene eroded the core of the Qigu anticline, which destroyed the initially large palaeo‐oil reservoir into smaller ones. The first‐stage hydrocarbon emplacement greatly affected the diagenesis and physical properties of the reservoir. It played an important role in inhibiting cementation, promoting dissolution, and altering the petrophysical properties of the tight sandstone reservoir. The densification process controlled the wettability and capillary pressure of pores in the tight sandstone. Specifically, the high kaolinite cement raised the hydrophilia, while the ubiquitous densification increased the capillary pressure of pores.

Fine Logging Evaluation of Fractures in Continental Tight Oil Sandstone Reservoirs of Yanchang Formation in the Ordos Basin

Fractures are the main seepage channels in tight reservoirs, and they affect the distribution of high-quality reservoirs and the enrichment of hydrocarbons. Fine logging identification of fractures in the strongly heterogeneous continental tight oil reservoirs of the Upper Triassic Yanchang Formation in the Ordos Basin is a hot and difficult point in the field of petroleum geology. In this paper, taking the Yanchang Formation as an example, a fractal model was constructed to identify fractures in tight oil reservoirs using a large number of cores, conventional and micro-resistivity imaging logging data. The results show that high-angle, vertical and bedding fractures are mainly developed in the Yanchang Formation tight sandstones. There is a negative correlation between sand body thickness and fracture development degree. The fracture sensitivity parameters were used to construct a coupled fractal fracture index. The fractal model incorporates logging information from natural gamma, acoustic wave time difference, rock density, and shallow lateral resistivity. In addition, the constructed fracture fractal index realizes the functions of multi-conventional logging information fusion, which can effectively identify fracture development segments in sandstone. According to the statistics, the fracture identification rate is 83.3%. The study also found that with the increase of sandstone brittleness index, the fracture index has a “S” shape increasing trend. Therefore, the content of brittle mineral components in sandstone is an important factor affecting the development degree of natural fractures, and fractures are more likely to occur in high brittle, thin sand bodies. The highly brittle framework minerals have strong stress-supporting capacity, which can keep fractures open by resisting high overlying loads.

Petrologic and geochemical characteristics of carbonate cements in the Upper Triassic Xujiahe Formation tight gas sandstone, western Sichuan Basin, China

Petrologic and geochemical characteristics of carbonate cements in the Upper Triassic Xujiahe Formation tight gas sandstone, western Sichuan Basin, China

Origin of authigenic kaolinite with implications for Permian tight gas sandstone reservoirs in the northern Ordos Basin, central China

This study deciphers the origin of authigenic kaolinite in the lower unit of Permian Shihezi Formation (P2x) tight gas sandstones in the Hangjinqi gas field, northern Ordos Basin, China, to determine its implications for reservoir quality. Authigenic kaolinite is the most abundant diagenetic cement and two occurrences of authigenic kaolinite are identified in the P2x sandstones: 1) in-situ replacive kaolinite; and 2) pore-filling kaolinite. Petrographic and geochemical evidence reveals that authigenic kaolinite is mainly derived from dissolution of K-feldspar via flushing with organic fluids from underlying source rocks. This evidence includes: 1) spatial association of partially dissolved K-feldspar and authigenic kaolinite; 2) the amount of K-feldspar dissolution is mostly equal to that of kaolinite precipitation within sandstones; 3) a homogenization temperature of 110–120 °C for aqueous inclusions in quartz overgrowths; 4) negative stable carbon isotopic compositions of calcite cements (δ13CPDB from −16.05‰ to −9.35‰). Dissolution of K-feldspar, coupled with precipitation of kaolinite and quartz, is interconnected fluid-rock interactions within sandstones that are inferred to simultaneously occur in a relatively closed system. Intra-formational diffusive transport is inferred to be the dominant transport mechanism during these fluid-rock interactions, which may result in precipitation of in-situ replacive kaolinite or pore-filling kaolinite. This transport pattern may have been localized (several centimeters to meters). The fluid-rock interactions lead to redistributional secondary porosity and would not significantly enhance total reservoir porosity. The occurrence of authigenic kaolinite greatly reduced reservoir permeability and gas saturation by occluding the pore-throats in the P2x sandstones.

Application of Various Machine Learning Techniques in Predicting Water Saturation in Tight Gas Sandstone Formation

Abstract Water saturation (Sw) is a vital factor for the hydrocarbon in-place calculations. Sw is usually calculated using different equations; however, its values have been inconsistent with the experimental results due to often incorrectness of their underlying assumptions. Moreover, the main hindrance remains in these approaches due to their strong reliance on experimental analysis which are expensive and time-consuming. This study introduces the application of different machine learning (ML) methods to predict Sw from the conventional well logs. Function networks (FNs), support vector machine (SVM), and random forests (RFs) were implemented to calculate the Sw using gamma-ray log, neutron porosity log, and resistivity (Rt) log. A dataset of 782 points from two wells (well-1 and well-2) in tight gas sandstone formation was used to build and then validate the different ML models. The dataset from well-1 was applied for the ML models training and testing, then the unseen data from well-2 were used to validate the developed models. The results from FN, SVM, and RF models showed their capability of accurately predicting the Sw from the conventional well logging data. The correlation coefficient (R) values between actual and estimated Sw from the FN model were found to be 0.85 and 0.83 compared to 0.98 and 0.95 from the RF model in the case of training and testing sets, respectively. SVM model shows an R-value of 0.95 and 0.85 in the different datasets. The average absolute percentage error (AAPE) was less than 8% in the three ML models. The ML models outperform the empirical correlations that have AAPE greater than 19%. This study provides ML applications to accurately forecast the water saturation using the readily available conventional well logs without additional core analysis or well site interventions.

Prediction of Water Saturation in Tight Gas Sandstone Formation Using Artificial Intelligence.

Water saturation (Sw) is a vital factor for the original oil and gas in place (OOIP and OGIP). Numerous available equations can be used to calculate Sw, but their values have been unreliable and strongly depend on core analyses, which are costly and time-consuming. Hence, this study implements artificial intelligence (AI) modules to predict Sw from the conventional well logs. Artificial neural networks (ANNs) and the adaptive neuro-fuzzy inference system (ANFIS) were applied to estimate Sw using gamma-ray (GR) log, neutron porosity (NPHI) log, and resistivity (Rt) log. A data set of 782 points from two wells (Well-1 and Well-2) in tight gas sandstone formation was used to develop and test the different AI modules. Well-1 was used to construct the AI models, then the hidden data set from Well-2 was applied to validate the optimized models. The results showed that the ANN and ANFIS models were able to accurately estimate Sw from the conventional well logging data. The correlation coefficient (R) values between the actual and estimated Sw from the ANN model were found to be 0.93 and 0.91 compared to 0.95 and 0.90 for the ANFIS model during the training and testing processes. The average absolute percentage error (AAPE) was less than 5% in both models. A new empirical correlation was established using the biases and weights from the developed ANN model. The correlation was validated with the unseen data set from Well-2, and the correlation coefficient between the actual and the estimated Sw was 0.91 with an AAPE of 6%. This study provides AI application with an empirical correlation to estimate the water saturation from the readily available conventional logging data without the requirement for experimental analysis or well site interventions.

Revisiting movable fluid space in tight fine-grained reservoirs: A case study from Shahejie shale in the Bohai Bay Basin, NE China

Assessment of movable fluid is a key topic in production of tight formations. Evaluation of the movable fluid was usually conducted on tight sandstone formations while rarely on black organic-rich shales. To analyze the movable fluid properties in tight black shales, we document the basic geochemical and petrological features of Paleogene Shahejie shale and carry out quantitative analyses of the movable fluid properties. A modified method is proposed to estimate the pore size distribution. Results indicate that Shahejie shale is characterized by a low porosity and under-saturated of movable fluid. Further, porosity and saturation of movable fluid in shales are mainly determined by the heterogeneity of pore structure. Besides, micropores and mesopores with pore radius smaller than 6.69–18.25 nm (the lower limits are calculated for the collected samples based on the low-field Nuclear Magnetic Resonance (LF-NMR) transverse relaxation time ( T 2 ) spectra, i.e., the lower limit is different for each sample) provide substantial movable space for the fluid. Previously, relaxation rate that related to conversion from T 2 spectra of porous media to pore size distributions is often regarded as constant as well as thickness of film fluid that produces pore surface relaxation. However, our work indicates that both the relaxation rate and thickness of film fluid are variables as a function of the pore radius. This study enriches the application of movable fluid properties in tight reservoirs formations, especially shales, and lays a foundation for tight porous media research using LF-NMR in future. • Movable fluid saturation indicates the exploitable rate of reservoir. • Movable fluid porosity is used to calculate the exploitable degree of reservoir. • The newly proposed method first employs nonconstant ρ 2 and h. • ρ 2 and h increase predictably as pore radius increases.

Bi-Fractal Characterization of the Pore Network of Tight Sandstone

Fluid seepage performance and accumulation in tight sandstone is a critical research topic for in-depth exploration and development, closely related to the heterogeneity of the pore network. The fractal characterization is one of the most compelling and direct ways for quantitative investigation of heterogeneity. However, only one kind of fractal is used in most studies, and the differences and relations between different fractal dimensions are rarely discussed. This paper chose one of the most representative tight sandstone formations in China, the second member of the Xujiahe Formation, as the research object. First, based on physical analysis and XRD analysis, we carried out a qualitative investigation on pore structure utilizing thin-section and scanning electron microscopy. Then, detailed pore structure parameters were obtained using high-pressure mercury intrusion (HPMI). Lastly, we combined two-dimensional fractal analysis on thin-section images and three-dimensional fractal analysis on HPMI data to characterize the pore network heterogeneity quantitatively. The Xu2 tight sandstone is mainly medium- to fine-grained lithic feldspathic sandstone or feldspathic lithic sandstone with low porosity and permeability. Also, the Xujiahe tight sandstone is mainly composed of quartz, feldspar, and clay. The pore types of Xu2 tight sandstones are primarily intergranular pores, micro-fractures, and intra- and intergranular dissolution pores. Moreover, most of the micro-fractures in gas-bearing formation are open-ended, while most are filled by clay minerals in the dry formation. The r50 (median pore radius) is the most sensitive parameter to seepage capability (permeability) and gas-bearing status. The 2D fractal dimension (Ds) of gas-bearing samples is significantly larger than that of dry samples, while the 3D fractal dimension (D1, D2) of gas-bearing samples is lower than that of dry samples. There is a strong negative correlation between D2 and gas-bearing status, permeability, quartz content, and r50, but a positive correlation between Ds and these parameters. D2 represents the heterogeneity of pore space, while the Ds indicates the development of the pore network. Tectonic movements that generate micro-fractures and clay cementation that blocks the seepage channels are the two main controlling factors on fractal dimensions. Combining 2D and 3D fractal analysis could give a more in-depth investigation of pore structure.

Effect of pore-throat structure on gas-water seepage behaviour in a tight sandstone gas reservoir

In this study, effect of pore-throat structure on gas–water seepage behaviour in a tight gas sandstone formation has been experimentally examined. More specifically, pressure-controlled mercury injection tests were performed to measure capillary pressure and identify the characteristics of a pore-throat structure such as its connectivity and size distributions. According to the pore-throat structure together with its median throat radius, pore-throat skewness, relative sorting coefficient, and cutoff throat volume ratio, the pore-throat structure was then classified into three types, while gas permeabilities under different conditions are corrected with consideration of the slippage effect and different pore-throat structures. Subsequently, seepage characteristics, including distribution of movable fluid saturation, relative permeability, and water locking degree, were quantified using displacement experiments integrated with the nuclear magnetic resonance (NMR) technique for the three classified types of pore-throat structure, respectively. With the deteriorated pore-throat structure, the throat size distribution curves are found to shift to the left, porosity gradually decreases, and the irreducible water saturation gradually increases. Both water saturation at the isotonic point and irreducible water saturation increase, and gas phase relative permeability at the irreducible water saturation together with water relative permeability within the saturation range of simultaneous gas–water flow decreases consecutively, indicating the seepage capacity of gas and water is weakened. With the deteriorated pore-throat structure, the water locking becomes more serious and its corresponding water saturation together with the damage coefficient of gas permeability is larger, and the influence of water on gas phase flow is more significant. The pore-throat structure, especially its connectivity, is found to be the main factor dominating the movable fluid saturation and two-phase seepage characteristics in a tight sandstone gas reservoir. This study allows us to better understand how the pore-throat structure affects the gas–water seepage behaviour in a tight gas reservoir, provided that its characterization has been quantitatively conducted and the seepage patterns are identified and classified within a consistent and unified framework. These findings further provides solid fundamentals for efficient and effective exploitation of tight gas reservoirs.

Geochemical Characteristics and Origin of Formation Water From the Upper Triassic Xujiahe Tight Sandstone in the Xiaoquan-Fenggu Structural Belt, Western Sichuan Depression, China

Formation water represents an important driving force and carrier for the migration and accumulation of oil and gas; thus, research on its origin is a hot spot in petroleum geology. The Upper Triassic Xujiahe Formation in the Xiaoquan-Fenggu Structural Belt in the western Sichuan Depression, China, has developed thick tight sandstone gas reservoirs. However, previous studies have provided different conclusions on the origin of the formation water in the Xujiahe tight sandstone reservoir. In this paper, the origin of the formation water in the Xujiahe Formation was determined based on the latest major and minor elemental concentration data, hydrogen and oxygen isotopes data of formation water, and carbon and oxygen isotope data of carbonate cements. The results show that the salinity of the formation water of the Xujiahe Formation in the study area is generally greater than 50 g/L. The water type is mainly the CaCl2 type, although a small proportion of NaHCO3 type water with high salinity is observed, which is related to hydrocarbon expulsion by overpressure. Moreover, the formation water in the sandstone of the Xujiahe Formation is obviously rich in Br, which is related to membrane infiltration, overpressured hydrocarbon expulsion of shale and diagenesis of organic matter. The composition of Cl− and Na+ ions in the formation water in the Xujiahe tight sandstone reservoir is consistent with the seawater evaporation curve, which deviates significantly from the freshwater evaporation curve. The hydrogen and oxygen isotopes of condensate water in the Xujiahe Formation tight sandstone are similar to those of atmospheric precipitation water, while the hydrogen and oxygen isotopes of the formation water in the Xujiahe Formation show that it is of seawater origin. Therefore, to use hydrogen and oxygen isotopes to determine the origin of formation water, condensate water must be accurately differentiated from formation water. Otherwise, if the condensate water is misjudged as formation water, then incorrect conclusions will be drawn, e.g., that the formation water of the Xujiahe Formation originated from fresh water. Affected by organic carbon, the carbon isotope Z value of the carbonate cements in the Xujiahe Formation is low (mainly distributed between 110 and 130). A Z value of less than 120 does not indicate that the ancient water bodies formed by cements were fresh water or mixed water bodies. However, Z values greater than 120 correspond to a formation temperature lower than 80 C, which indicates that carbonate cement was not affected by organic carbon; thus, the Z value can reflect the origin of ancient water bodies. The results of this study indicate that the formation water of the Xujiahe tight sandstone in the study area is of seawater origin. The determination of the origin of the formation water and seawater of the Xujiahe Formation provides strong evidence for the determination of the marine sedimentary environment of the Xujiahe Formation in the study area, and can provide scientific guidance for the search for high-quality reservoirs.

Pore throat characteristics of tight reservoirs by a combined mercury method: A case study of the member 2 of Xujiahe Formation in Yingshan gasfield, North Sichuan Basin

Abstract The complex pore throat characteristics are significant factors that control the properties of tight sandstone reservoirs. Due to the strong heterogeneity of the pore structure in tight reservoirs, it is difficult to characterize the pore structure by single methods. To determine the pore throat, core, casting thin sections, micrographs from scanning electron microscopy, rate-controlled mercury injection, and high-pressure mercury injection were performed in member 2 of Xujiahe Formation of Yingshan gasfield, Sichuan, China. The pore throat characteristics were quantitatively characterized, and the distribution of pore throat at different scales and its controlling effect on reservoir physical properties were discussed. The results show that there are mainly residual intergranular pores, intergranular dissolved pores, ingranular dissolved pores, intergranular pores, and micro-fractures in the second member of the Xujiahe Formation tight sandstone reservoir. The distribution range of pore throat is 0.018–10 μm, and the radius of pore throat is less than 1 μm. The ranges of pore radius were between 100 and 200 μm, the peak value ranges from 160 to 180 μm, and the pore throat radius ranges from 0.1 to 0.6 μm. With the increase of permeability, the distribution range of throat radius becomes wider, and the single peak throat radius becomes larger, showing the characteristic of right skew. The large throat of the sandy conglomerate reservoir has an obvious control effect on permeability, but little influence on porosity. The contribution rate of nano-sized pore throat to permeability is small, ranging from 3.29 to 34.67%. The contribution rate of porosity was 48.86–94.28%. Therefore, pore throat characteristics are used to select high-quality reservoirs, which can guide oil and gas exploration and development of tight sandstone reservoirs.

Three-Dimensional Ultrasonic Imaging and Acoustic Emission Monitoring of Hydraulic Fractures in Tight Sandstone

Hydraulic fracturing is an important means for the development of tight oil and gas reservoirs. Laboratory rock mechanics experiments can be used to better understand the mechanism of hydraulic fracture. Therefore, in this study we carried out hydraulic fracturing experiments on Triassic Yanchang Formation tight sandstone from the Ordos Basin, China. Sparse tomography was used to obtain ultrasonic velocity images of the sample during hydraulic fracturing. Then, combining the changes in rock mechanics parameters, acoustic emission activities, and their spatial position, we analyzed the hydraulic fracturing process of tight sandstone under high differential stress in detail. The experimental results illuminate the fracture evolution processes of hydraulic fracturing. The competition between stress-induced dilatancy and fluid flow was observed during water injection. Moreover, the results prove that the “seismic pump” mode occurs in the dry region, while the “dilation hardening” and “seismic pump” modes occur simultaneously in the partially saturated region; that is to say, the hydraulic conditions dominate the failure mode of the rock.

The Use of Well-Log Data in the Geomechanical Characterization of Middle Cambrian Tight Sandstone Formation: A Case Study from Eastern Pomerania, Poland

Geomechanical characterization plays a key role in optimizing the stimulation treatment of tight reservoir formations. Petrophysical models help classify the reservoir rock as the conventional or unconventional type and determine hydrocarbon-saturated zones. Geomechanical and petrophysical models are fundamentally based on well-log data that provide reliable and high-resolution information, and are used to determine various relationships between measured borehole parameters and modeled physical rock properties in 3D space, with the support of seismic data. This paper presents the geomechanical characterization of the Middle Cambrian (Cm2) sediments from Eastern Pomerania, north Poland. To achieve the aim of this study, 1D well-log-based and 3D models based on seismic data of the rocks’ petrophysical, elastic, and strength properties, as well as numerical methods, were used. The analysis of the Middle Cambrian deposits revealed vertical and horizontal heterogeneity in brittleness, the direction of horizontal stresses, and the fracturing pressure required to initiate hydraulic fractures. The most prone to fracturing is the gas-saturated tight sandstones belonging to the Paradoxides Paradoxissimus formation of Cm2, exhibiting the highest brittleness and highest fracturing pressure necessary to stimulate this unconventional reservoir formation.

Effects of micro-fracture and micro-coal line on tight gas accumulation, Triassic Xujiahe Formation, Sichuan Basin, China

The study of natural gas migration and accumulation of tight gas has become the focus of the energy industry in recent years. One of the priorities is the research of hydrocarbon migration carrier system of the formation. This study reveals two types of hydrocarbon carrier systems (micro-fractures and micro-coal lines) in the tight formation through a large amount of geological observations, data statistics, and simulations. This study also first put forward the view that the coal lines can be a type of hydrocarbon carrier system in tight sandstone formation. During the research process, an improved permeability testing method and apparatus are used to test the core permeability widely. Based on the real core, three models are established to describe the micro-fracture/micro-coal line characteristics. According to the three typical models, the Voronoi method is used to rebuild the network models. The migration and accumulation process in tight formation is simulated with the Multiple Relaxation Time lattice Boltzmann method in numerical simulation and with displacement apparatus in physical simulation. The results indicate that the micro-fracture/micro-coal line will significantly improve the percolation capacity of sandstone as the hydrocarbon migration carrier system in tight formation, the mechanism is revealed by numerical simulations. The micro-fractures/micro-coal lines are favorable for natural gas accumulation in tight formation. Unlike the conventional formation, in tight formation, micro-fractures/micro-coal lines tend to be the main migration carrier systems during the gas accumulation process.

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.

The Origin of Quartz Cement in the Upper Triassic Second Member of the Xujiahe Formation Sandstones, Western Sichuan Basin, China

High-precision in situ δ18O values obtained using secondary ion mass spectrometry (SIMS) for μm-size quartz cement are applied to constrain the origin of the silica in the deep-buried Upper Triassic second member of Xujiahe Formation tight sandstones, western Sichuan Basin, China. Petrographic, cathodoluminescence (CL), and fluid inclusion data from the quartz cements in the Xu2 sandstones indicate three distinct, separate quartz precipitation phases (referred to as Q1, Q2, and Q3). The Q1 quartz cement was formed at temperatures of approximately 56–85 °C and attained the highest δ18O values (ranging from 18.3 to 19.05‰ Vienna Standard Mean Ocean Water (VSMOW)). The Q2 quartz cement was generated at temperatures of approximately 90–125 °C, accompanying the main phase of hydrocarbon fluid inclusions, with the highest Al2O3 content and high δ18O values (ranging from 15 to 17.99‰ VSMOW). The Q3 quartz cement was formed at temperatures of approximately 130–175 °C, with the lowest δ18O values (ranging from 12.79 to 15.47‰ VSMOW). A portion of the Q2 and Q3 quartz cement has a relatively high K2O content. The dissolution of feldspar and volcanic rock fragments was likely the most important source of silica for the Q1 quartz cement. The variations in δ18O(water) and trace element composition from the Q2 quartz cement to the Q3 quartz cement suggest that hydrocarbon emplacement and water-rock interactions greatly altered the chemistry of the pore fluid. Feldspar dissolution by organic acids, clay mineral reactions (illitization and chloritization of smectite), and pressure dissolution were the main sources of silica for the Q2 and Q3 quartz cements, while transformation of the clay minerals in the external shale unit was a limited silica source.

The Evolution of Diagenetic Fluids and Accumulation Characteristics of Tight Sandstone Reservoir in Upper Paleozoic, Southwestern Ordos Basin

The Upper Paleozoic in the southwestern Ordos Basin has significant potential for natural gas exploration. This study investigated the diagenetic fluid evolution and hydrocarbon accumulation characteristics of He 8 section from Permian Lower Shihezi formation and Shan 1 section from Shanxi formation tight sandstone reservoirs by petrographic observation, scanning electron microscope imaging, fluid inclusion study, and laser Raman spectrum analysis. The results show that He 8 section and Shan 1 section reservoirs are mainly composed of quartz sandstone, subordinate arkose quartz sandstone, and lithic quartz sandstone, with minor lithic sandstone and lithic arkose sandstone. The major pores are intergranular dissolved pores. The main diagenetic minerals include quartz overgrowth, siliceous cement, carbonate cement, illite, montmorillonite, and mixed-layer clay minerals. The overall diagenetic features show strong compaction, multistage siliceous and calcareous cements, and abundant clay minerals, strong dissolution, and well-developed fractures. Two stages of fluid inclusions developed in the He 8 and Shan 1 sections recorded the migration and accumulation of the early-stage and late-stage natural gas, respectively. The reservoir in the study area experienced early and late diagenetic stages, and its formation was simultaneous with or after its densification. The diagenetic environment changed from alkaline to acidic and again into alkaline. There are two stages of fluid activities in the study area, namely, the early diagenetic stage corresponding to hydrocarbon generation and migration and the late diagenetic stage corresponding to hydrocarbon accumulation. This study suggests that Upper Paleozoic natural gas migrated into the reservoir in Weibei Uplift, Yishan Slope, and Tianhuan Depression tectonic units during 220-197 Ma, and the large-scale migration and accumulation occurred in these tectonic units at different times. No natural gas was generated in the west margin of the basin because the temperatures of the hydrocarbon source rocks in the Upper Paleozoic were below the gas window.

Dicationic Surfactants as an Additive in Fracturing Fluids to Mitigate Clay Swelling: A Petrophysical and Rock Mechanical Assessment.

The interactions of clays with freshwater in unconventional tight sandstones can affect the mechanical properties of the rock. The hydraulic fracturing technique is the most successful technique to produce hydrocarbons from unconventional tight sandstone formations. Knowledge of clay minerals and their chemical interactions with fracturing fluids is extremely vital in the optimal design of fracturing fluids. In this study, quaternary ammonium-based dicationic surfactants are proposed as clay swelling inhibitors in fracturing fluids to reduce the fractured face skin. For this purpose, several coreflooding and breakdown pressure experiments were conducted on the Scioto sandstone samples, and the rock mechanical properties of the flooded samples after drying were assessed. Coreflooding experiments proceeded in a way that the samples were flooded with the investigated fluid and then postflooded with deionized water (DW). Rock mechanical parameters, such as compressive strength, tensile strength, and linear elastic properties, were evaluated using unconfined compressive strength test, scratch test, indirect Brazilian disc test, and breakdown pressure test. The performance of novel synthesized surfactants was compared with commercially used clay stabilizing additives such as sodium chloride (NaCl) and potassium chloride (KCl). For comparison, base case experiments were performed with untreated samples and samples treated with DW. Scioto sandstone samples with high illite contents were used in this study. Results showed that the samples treated with conventional electrolyte solutions lost permeability up to 65% when postflooded with DW. In contrast, fracturing fluid containing surfactant solutions retained the original permeability even after being postflooded with DW. Conventional clay stabilizing additives led to the swelling of clays caused by high compression and tensile strength of the rock when tested at dry conditions. Consequently, the rock fractures at a higher breakdown pressure. However, novel dicationic surfactants do not cause any swelling, and therefore, the rock fractures at the original breakdown pressure.