Tight Sand Research Articles

Permeability prediction of isolated channel sands using machine learning

Permeability prediction has long been one of the most important and difficult tasks of reservoir characterization, especially for tight sands with strong heterogeneity. A unified model is important for the un-cored wells and can reduce a lot of work in practice. In this case, we are going to establish a field-scale unified permeability model for the tight gas sands of the Middle Jurassic Shaximiao Formation in the Western Sichuan Basin, China. The tight gas sands are isolated channel sands with strong heterogeneity. In addition to the porosity, well logs are also selected as the input feature to help to derive the non-linear relations. We choose simple linear regression (SLR) using porosity, multiple linear regression (MLR), multiple-layer perceptron (MLR) and support vector regression (SVR) using multiple input features as our machine learning methods for this task. For the non-linear methods, MLP and SVR, we present how to decide their key parameters based on the theoretical analysis and experiments to keep their generalization capability. Finally, the results show that the non-linear MLP and SVR outperform the linear SLR and MLR for the unified permeability model. The blind well average performance of MLP and SVR improves about 50% on R2 and decrease about 30% on MARE than MLR.

Evaluation of the near fracture face formation damage caused by the spontaneously imbibed fracturing fluid in unconventional gas reservoirs

In the present study, spontaneous imbibition experiments, steady-state permeability measurements, and numerical simulation were integrated to quantify the changes in the effective water permeability, capillary pressure, and water relative permeability curves due to the polymer adsorption of the spontaneously imbibed fracturing fluid. The effect of the nonionic surfactant and core bedding plane on the fluid spontaneous imbibition volumes were also investigated.The researchers considered the impact of the spontaneous imbibition of a friction reducer fluid in tight sand and shale core samples. Three comparative systematic spontaneous imbibition experiments were conducted for each of the core samples using brine, anionic friction reducer fluid, and brine again. The core sample water permeability before and after the imbibition experiment was measured using a constant rate steady-state permeability apparatus.The polymer adsorption from the spontaneously imbibed fracturing fluid significantly reduced the brine spontaneous imbibition volumes in tight sand samples and in shale samples, though to a lesser degree. Moreover, the effective water permeability was decreased because of the polymer adsorption effect. Therefore, the polymer adsorption during hydraulic fracturing reduces the fluid leak-off into the formation and also the fluid flowback.The nonionic surfactant increased the fluid spontaneous imbibition volumes in both tight sand and shale samples. Thus, adding a nonionic surfactant to the friction reducer pad fluid during hydraulic fracturing leads to enhance both of the fluid leak-off and fluid flowback. The results also showed that the effect of polymer adsorption on the imbibition rates is less when the rock-fluid contact surface is parallel to the bedding plane.The imbibition potentials and imbibition capillary pressure curves were calculated before and after polymer adsorption. The polymer adsorption led to a slight increase in the capillary pressure; moreover, the tight sand samples had higher capillary pressure than the shale samples. The imbibition water relative permeability curves were calculated using ECLIPSE commercial simulator. The polymer adsorption significantly reduces the water relative permeability curves for tight sand samples and in less degree for shale samples.

Two episodes of structural fractures: Numerical simulation of Yanchang Oilfield in the Ordos basin, northern China

Abstract The tight oil sand reservoirs of the Yanchang Oilfield in the Upper Triassic Yanchang 6, 7, and 8 Formations (T3Yc6,7,8 Fms.) in the Ordos Basin are in the exploration stage. Two episodes of fractures during the Yanshanian and Himalayan periods, observed in outcrops and cores of the T3Yc6,7,8 Fms., are thought to be the controlling factors for the tight oil ‘sweet spot’. Finite element numerical simulation (FES) technology is used to perform a three-dimensional (3D) fracture simulation for a large region during the exploration stage, to serve in tight oil reconnaissance for the Yanchang Oilfield. The innovations of our work are mainly shown in the following simulation process: (1) three controlling factors, including the paleotopography, layer thickness and rock mechanical faces, are used to construct the 3D geologic model in the simulation; (2) the rock mechanical environment, characterized by the An'gou, Qiliha-Zhangjiatan and Dongjiahe outcrops, the Y1011 well cores and the corresponding mechanical experimental parameters, is divided into three types as follows: the delta front - tractive current - sand faces (DF-Tr-S), the lacustrine - turbidity current - sand faces (L-Tu-S) and the mud faces (M); (3) the spatial boundary stress conditions are calculated based on the Newberry formula for tensional and compressional stress fields, considering the synthetical effects of the overburden pressure, the pore-fluid pressure and the tectonic stress; (4) the modified Griffith's criterion is used to fit the fracture index by simultaneously taking into consideration the tension and shear fracture mechanisms. For the simulation results, the predicted fracture index distribution map agrees well with the measured fracture density. The Yanshanian fractures mainly propagated in the Dingbian and An'bian areas adjacent to the western thrust belt, while the Himalayan fractures mainly propagated in the Zhidan, Fuxian, and Huangling areas adjacent to the Weihe Graben. The simulated fracture index has a positive correlation with the stratigraphic dip and a negative correlation with the layer thickness. Additionally, structural fractures are prone to propagate near the mechanical interface in either the upward or downward penetration direction and are assumed to produce a fracture-type sweet spot section in the vertical direction. The reservoir oiliness also increases with the simulation fracture index, indicating the fracture-type tight oil sweet spot of the Yanchang Oilfield. Moreover, the critical components used in the 3D fracture FES, including the 3D geologic model, the spatial boundary stress conditions and the fracture index fitted by the modified Griffith criterion, can be of great significance to produce more accurate numerical simulations during the oil and gas exploration stage in large regions.

NMR Characterization of Pore Structure and Connectivity for Nano-self-assembly γ-Al2O3 and Precursor

Nano-self-assembly γ-Al2O3 (NSAA) is a catalytic material and can be used as a physical model of micro–nano-porous material for understanding shale and tight formations. Herein, we describe the development of an in situ, fast, and quantitative method for the potential nuclear magnetic resonance (NMR) characterization of pore system in a nano-self-assembly precursor (NSAP) for the first time. The surface relaxivity ρ2 of small pores, which are water saturated is found to be 0.65 and 0.85 μm μs−1, while ρ2 for large pores, which are hydrocarbon saturated is 0.55 μm μs−1. This points to the interaction of water molecules with inorganic pore surface being stronger than that of hydrocarbon molecules. A new method for reconstructing the capillary pressure curve (Pc) is used to comprehensively reflect the pore structure of NSAA and predict NMR Pc. The pore network model of NSAA is proposed based on NMR quantitative characterization and SEM evaluation, and it has pore channels, which are suitable for macromolecule diffusion. A set of low-field NMR methods for evaluating the pore connectivity of nanomaterials are established. The experiments demonstrate that low-field NMR is a robust tool for characterizing pore channels for macromolecule transport in catalytic materials, with an important application field being shale oil and tight sand oil development and petroleum refining.

Selection of failure criteria for estimation of safe mud weights in a tight gas sand reservoir

In an undisturbed state, a stress field present in the earth consists of virgin stress in the rock. A change in this stress occurs due to drilling the borehole and disturbing the original stress by either introducing drilling fluids or by getting reservoir flow in the borehole. This change in stress leads to a classical problem of well bore instability. To resolve wellbore instability, evaluation of rock mechanical properties and in-situ stresses is essential. The output of this study is evaluation of safe mud weights which is critical to safe drilling. If the mud weight used for drilling is higher than those predicted by the failure criteria, the mud percolates into the formation, causing tensile failure (fracture stress) which induces fluid losses. Conversely, the lower mud weight results in shear failure (collapse stress) of rock leading to borehole breakout and collapse of wellbore. Three types of failure criteria i.e. Mohr-Coulomb, Mogi-Coulomb and Modified Lade are considered in this study. The stress around the wellbore is obtained using Kirsch equation. The input parameters required for estimating the safe mud weights from these failure criteria are rock mechanical properties, friction angle and cohesion which are estimated from well log data. The rock mechanical properties like Poisson's ratio and Uniaxial Compressive Strength are computed using sonic derived compressional and shear velocities. Internal friction angle is obtained using gamma ray log and is validated with core data before it is used in further analysis. The failure criteria have been applied to two wells located in a field in Gulf of Oman. The analyses show that the Mohr-Coulomb overestimates the mud weight while the Modified Lade criterion underestimates it. The result for a tight gas sand reservoir suggests that the Mogi-Coulomb predicts better mud weight values that are in agreement to those measured values chosen for drilling.

Gas accumulation conditions and key technologies for exploration & development of Sulige gasfield

Up to now, the Sulige area in Ordos Basin has the favorable exploration area of 55 × 103 km2, the total reserve of natural gas of nearly 6 × 1012 m3 and the proven reserve (including basic proven reserve) of 4.77 × 1012 m3, where the annual production of natural gas reaches 23 × 109 m3, and the Sulige gasfield is the largest onshore natural gas field in China. The pay zone of the Sulige gasfield mainly is Member 8 of Shihezi Formation and Member 1 of Shanxi Formation of Permian which belong to the typical tight sandstone gas reservoir. The coal measure strata in Carboniferous Benxi Formation, Permian Taiyuan Formation and Shanxi Formation provide abundant gas sources for the Gulige gas reservoirs. An open-flow sedimentary model of lacustrine delta is developed, the gentle bottom, sand supply from multi-source, strong hydrodynamic force and multi-period superposition control the distribution of large-area reservoir sand body. Lithology of the reservoir is the sandstone of the fluvial-delta facies, the physical property is poor and the heterogeneity is strong, the average porosity ranges from 4% to 12% and the average permeability varies from 0.01 to 1 mD. The gas reservoir is characterized by wide hydrocarbon generation, pervasive hydrocarbon charging, short-range migration and massive accumulation. The pressure coefficient of the gas reservoir ranges from 0.62 to 0.90, indicating the low-pressure gas reservoir, and the single-well yield is low. Full digital seismic technique in the desert area, non-longitudinal seismic technique in the loess plateau, accurate logging evaluation technique, tight sand reservoir stimulation technology and horizontal well development technology are key technologies for exploration and development of Sulige gasfield.

Numerical simulation of hydraulic fracture initialization and deflection in anisotropic unconventional gas reservoirs using XFEM

Unconventional gas reservoirs, e.g., coal, shale, or tight sand, are generally anisotropic. However, the propagation mechanism of hydraulic fractures in an anisotropic reservoir has not been well studied. By means of XFEM, the influence of the anisotropic characteristics of reservoirs, including the perforation direction on the propagation of hydraulic fractures is studied in this paper. The initialization and deflection angle of a hydraulic fracture are governed by the modified maximum circumferential tensile stress criterion. The crack tip stress field is calculated by the theoretical solutions of stress complex variable functions, which are suitable for anisotropic materials. It is shown that the deflection angle increases with the increasing of reservoir anisotropic degree when the perforation fracture is in the principle direction that the rock is hardest to be cracked. However, the fracture does not deflect when the fracture toughness ratio and the elasticity modulus ratio in different directions are small. The critical fracture toughness ratio when a hydraulic fracture begins to deflect decreases exponentially with the increasing of elasticity modulus ratio. In addition, deflection angle of a hydraulic fracture in an anisotropic reservoir dependents a lot on the perforation direction.

Determination of target-oriented parameters for computation of curvature attributes

The application of curvature attributes on seismic horizons or 3D seismic volumes has been discussed in the literature in several ways. Such discussion largely ignores the detail of parameter selection that must be made by the working interpreter or the expert processor. Parameter selection such as window size and filtering methods for seismic curvature estimates have not been extensively compared in the literature and have never been validated using quantitative ground truthing to log or drilling data. Of even greater relevance to the interpreter is the lack of discussion of curvature parameters as they are relevant to interpretive and operational concerns. We focus on the seismic most-positive curvature attribute, its parameterization, and filtering for the overpressured tight sand target in the Falher F formation of the deep basin of Alberta, Canada. This sand has numerous natural fractures that constitute an occasional drilling hazard due to mud losses. Various parameterizations on horizon- and volume-based curvature extractions are made and examined in the context of the drilling results of four horizontal wells, one of which has image log fracture density along the lateral portion of the well. We compared different lateral (and vertical where applicable) window sizes in the initial curvature estimates, as well as different postcurvature filtering approaches including unfiltered, Gaussian-filtered, and Fourier-filtered products. The different curvature attribute estimates have been evaluated by way of map comparisons, cross-section seismic line comparisons, and correlations with the upscaled fracture density log data. We found that our horizon-based estimates of positive curvature suffered from mechanical artifacts related to the horizon picking process, and the volume-based methods were generally superior. Of the volume-based methods, we found that the Fourier-filtered curvature estimates were the most stable through smaller analysis windows. Gaussian-filtering methods on volumetric curvature gave results of varying quality. Unfiltered volumetric curvature estimates were only stable when very large time windows were used, which affected the time localization of the estimate. The comparisons give qualitative and quantitative perspective regarding the best parameters of curvature to predict the key properties of geologic target, which in this case are the potentially hazardous natural fractures within the overpressured Falher F sandstone.

A method to determine nuclear magnetic resonance (NMR) T2cutoff based on normal distribution simulation in tight sandstone reservoirs

The T2cutoff is an important input parameter in nuclear magnetic resonance (NMR) applications. The accuracy of the T2cutoff affects the prediction reliability of parameters associated with the identification and evaluation of formations. Current methods are based on regional statistics; they have limited applications and the predicted values are not always reliable. In this study, a total of 36 core samples, drilled from Triassic tight sandstone reservoirs of the southwest Ordos Basin in China, were used for laboratory NMR measurements under fully brine saturated and irreducible water conditions. Based on the morphological character analysis of experimental NMR T2 spectra, we demonstrate that NMR T2 spectra can be fully simulated using the normal distribution function. In addition, a new method was proposed, which can predict various T2cutoffs based on the morphological differences of NMR T2 spectra, and the irreducible water saturation (Swirr) was calculated, which represents the ratio of the sum volume of clay bound water and capillary bound water to total pore volume. The reliability of this method was verified by comparing the predicted T2cutoff and Swirr values with those of core NMR experimental results. Finally, we extended this method into field applications in several tight sandstone reservoirs in China. The results show that total T2 distributions of the formation were fully simulated by the normal distribution function, and various T2cutoff and Swirr values were precisely predicted. Meanwhile, tight sands permeability curves, predicted based on the Timur-Coates model, were also accurately estimated. The results of our study may be applied to improve tight sandstone reservoir identification and evaluation using NMR logs.

Determining the Occurrence of Oil in Micro/Nanopores of Tight Sand: A New Approach Using Environmental Scanning Electron Microscopy Combined with Energy-Dispersive Spectrometry

The use of fluorescence slices and other regular methods tend to be limited in resolution as a result of optical microscopy issues when they are applied to characterize oil occurrences in tight san...

The characteristics of tight oil sand reservoir-source assemblage in lacustrine basins: A case study of the Cretaceous Qingshankou Formation, Songliao Basin, northeast China

The complicated source-reservoir-assemblage characteristics of lacustrine tight oil sand in China are the main controlling factors of tight reservoir oiliness (i.e., oil richness). Several studies have focused on qualitative description of source-reservoir-assemblage characteristics without quantitative assessment. In this study, reservoir-source-assemblage (RSA) has been evaluated quantitatively by fitting the RSA log in the evaluation of Qijia Depression in the Songliao Basin. Total organic carbon (TOC) and sand volume (Vs) logs are used to fit the RSA log in three steps: (1) TOC and Vs log fitting and normalization, (2) RSA log fitting, and (3) extraction of root-mean-square (rms) amplitude and frequency (Frq(0)) information from the RSA log. The rms represents the reservoir capability and hydrocarbon potential, and Frq(0) represents the interbedding frequency that changes with the lake level. Positive values (0–1] of the RSA log correspond to a high lake level, whereas negative values [[Formula: see text], 0) correspond to a low lake level. Based on RSA log values, we defined the parameter RSAsuf, a product of rms and Frq(0), to quantitatively evaluate the tight oil sweet spot. RSAsurf serves as tight oil sweet spot indicator and correlates positively to oil richness. As a result, four types of effective reservoirs (RI, RII, RIII, and RIV), two types of effective sources (SI and SII), and three types of RSAs (R-S-R, S-R-S, and S-S-R) are identified based on cores and RSA logs. High RSAsuf values on the isoline map indicate the sweet spot zones around the G933 and J392 well areas, which correlates very well with the oilfield test data. The approach is appropriate for lacustrine basins with complicated RSA, in which RSA logs serve as indicator for the sedimentary rhythm, reservoir capability, and hydrocarbon potential.

Array Processing in Microseismic Monitoring: Detection, Enhancement, and Localization of Induced Seismicity

Current development of unconventional resources (such as shale gas, shale oil, and tight sands) requires hydraulic fracturing, which involves injecting fluid at high pressure into the subsurface reservoir. Such injections (or fluid production) cause stress changes in the reservoir. These stress changes often result in failure of the rocks with a concurrent release of seismic energy as seismic waves. The nature of seismic wave propagation in the subsurface media is complex. Based on the direction of propagation and the particle motion, body waves can be classified into P-waves (primary, compressional wave) and S-waves (secondary, shear wave). Passive seismic monitoring is based on recording these emitted waves and then using signal processing to extract characteristics such as amplitude, polarity, and arrival time, from which it is then feasible to estimate the location and character of the failure events.

Characteristics of the tight sand reservoirs in the delta front in the Xu-2 Member of the Upper Triassic Xujiahe Formation (Hechuan area of the central Sichuan Basin, SW China)

The Xu-2 Member of the Upper Triassic Xujiahe Formation (Hechuan area, southwestern China) is an important potential sedimentary sequence for gas exploration in the central Sichuan Basin. Thus, we performed a comprehensive study of drilling parameters, sedimentary cores, well logging, and core test data and combined our results with previous research and the geological background of the basin. We found that the Hechuan area was a delta front that included underwater distributary channels, interchannels, and mouth and distal bars during deposition of the Xu-2 Member. The sand body genetic types were divided into three categories based on where they developed: an underwater distributary channel, a mouth bar, or a distal bar. The lithology of the Xu-2 reservoirs is mainly feldspathic litharenite, lithic arkose, subarkose, litharenite, and sublitharenite. Residual intergranular pores and intergranular dissolution pores are the major pore types in the reservoirs. Reservoirs with porosities of 0.18–15.84% and permeabilities of 0.001–8.72 × 10−3 μm2 showed a correlation coefficient of 0.7592. The reservoir throats are mainly tubular and constricted. Overall, the sedimentary environment and diagenesis are the major controlling factors for reservoir formation in the study area. The reservoir zones with relatively high porosity and permeability mainly developed in a delta front with underwater distributary channels and mouth bars. Chlorite growth preserved the primary pores during early diagenesis stage B, and intergranular dissolution pores resulted from contact with organic acids derived from source rocks during middle diagenesis stage A1. Compaction and cementation significantly decreased porosity during middle diagenesis stage A2. These important factors influenced reservoir quality.

Composite linear flow model for multi-fractured horizontal wells in tight sand reservoirs with the threshold pressure gradient

Multi-stage fracturing is currently the most effective method to exploit tight sand reservoirs. Various analytical models have been proposed to fast and accurately investigate the post-fracturing pressure- and rate-transient behavior, and hence, estimate the key parameters that affect well performance. However, these analytical models mainly consider the 2D flow, neglecting the fluids’ flow from the upper/lower reservoir when the vertical fractures partially penetrate the reservoir. Although for linear flow models, Olarewaju and Lee (1989) and Azari et al. (1990, 1991) have studied the effects of fracture height, they merely used a skin factor. Moreover, the reservoir heterogeneity is seldom included. This paper presents an analytical model for multi-fractured horizontal wells (MFHWs) in tight sand reservoirs, accounting for the upper/lower reservoir contributions, reservoir heterogeneity and threshold-pressure gradient (TPG).The model is extended from the “five-flow-region” model and subdivides the reservoir into seven parts including two upper/lower flow regions, two outer flow regions, two inner flow regions and a hydraulic fracture flow region. Reservoir heterogeneity along the horizontal wellbore is considered, thus, the effects of the fracture pattern in a heterogeneous reservoir are documented. Fracture interference is simulated by locating a virtual no-flow boundary between two adjacent fractures. The exact location of a no-flow boundary is determined based on the boundary's pressure. Thus, the no-flow boundary has a minimum pressure difference between its two sides during the well production, making the no-flow assumption reasonable. The experimentally observed TPG and the pressure drop within the horizontal wellbore are included.Modeling results are compared with those from the well-testing software KAPPA Ecrin, obtaining a good match in most flow regimes. Both the constant-rate and constant-pressure conditions are studied. Results suggest that the fracture penetration ratio dominates the early-mid time pressure responses and the start time of the boundary-dominated flow. For production responses, it determines the initial productivity and the production decline rate. The existence of the TPG results in a higher pressure drop and accelerates the production decline during the middle-late times. But this influence is marginal when the TPG is small (TPG<0.4psi/ft). Effects of other relative parameters, such as the formation permeability, fracture length, conductivity, fracture pattern, wellbore storage, flow-capacity ratio and storativity ratio for dual-porosity reservoir blocks are systematically investigated. Besides, some field data are analyzed and compared graphically, using type curve matching, and reliable results are obtained.Low CPU demands and the minimal data requirement of this model enable the operators to predict well-testing results under different fracture patterns in heterogeneous reservoirs with TPGs in a simple but effective way.

Experimental evaluation of near wellbore stimulation – using electrical explosion shockwave on tight sand reservoir

In recent years, the application of electrical explosion shockwave as a stimulation technology is increasing in oil fields, but lacks relevant theoretical knowledge to support it. In view of this problem, a research was carried out on experimental study of electrical explosion shockwave stimulation on the tight sand reservoir to determine the effective range of the resulting effects. An experimental platform for testing electrical explosion shockwave is established. Porosity, permeability and other mechanical parameters of tight sand stone samples are tested before and after electrical explosion shockwave treatment. The result shows clear improvement of the above mentioned parameters and the effective range.

A Method of Calculating Saturation for Tight Sandstone Reservoirs: A Case of Tight Sandstone Reservoir in Dabei Area of Kuqa Depression in Tarim Basin of NW China

The tight sand reservoir in Dabei Area has been the main block of exploration and development of natural gas inTarimBasin. Because of low porosity and fracture development, there exist errors in calculation of reservoir saturation. According to micro-resistivity image logging and acoustic full-wave logging, the reservoir fractural effectiveness is quantitatively evaluated; the result indicates that the reservoir with Stoneley wave permeability is greater than 0.2 × 10-3μm2; the reservoir connection is good. If the FVPA is greater than 0.055%; the fractures are developed. A new matrix saturation model is established based on the conductive pore water in consideration of the influence of low porosity. After modeling and analyzing the effect of porosity and its occurrence on the cementation index, the method for saturation calculation in Kuqa Area is established: the newly established dual porosity model is for fracture developed reservoirs, and the model based on the conductive pore water is for fracture less-developed reservoirs. By comparing the results of saturation in mercury injection experiment from coring section, precision of the calculation method is proven.

鄂尔多斯盆地东缘XE气田上古生界致密砂岩储层特征及主控因素

鄂尔多斯盆地东缘XE气田上古生界致密砂岩储层特征及主控因素

Effects of early oil emplacement on reservoir quality and gas migration in the Lower Jurassic tight sand reservoirs of Dibei gas field, Kuqa Depression, western China

It is common for many tight gas sandstone reservoirs to have experienced an early oil charge before gas invading. To determine the effects of early oil emplacement on reservoir quality and gas migration has important role in predicting “sweet spots” of gas production in tight sand reservoirs. We investigated the palaeo and current fluids contacts accurately due to parameters from quantitative grain fluorescence in the Lower Jurassic Ahe Formation of Dibei gas field. The porosity and permeability values in palaeo-oil leg are totally higher than in palaeo-water leg, especially there being a wide gap of permeability with an order of magnitude. The variation of reservoir quality derives from the early oil emplacement, which restrained clay conversions from kaolinite or illite-smectite mixed-layer into fibrous illite that dramatically increasing flow-path tortuosity in sandstones, according to core analysis and X-ray diffraction. The early oil preserved penetrating quality of palaeo-oil leg, but the sandstones that never experienced early oil emplacement contains much more fibrous illite. It made most of early oil pathways subsequently act as the migration pathways for late gas and less than 50% of the migration pathways for gas were caused by microfractures due to quantitative grain fluorescence. Only the sandstones with medium early oil saturation did become sweet spots for gas in the tight sand reservoirs. Too much and too little oil once saturated in pores maybe adverse to the late gas migration and accumulation.

Conventionally trapped natural gas accumulations in the Jurassic tight sandstone reservoirs: A case study from the Center of the Western Sichuan Basin, SW China

Tight gas accumulations, commonly characterized by low permeability, low porosity, and complicated pore structure, are widely distributed in the Sichuan Basin. Recent exploration in the Chengdu Sag, Western Sichuan Basin has proven that Jurassic tight-sandstone reservoirs attach significant gas potential. However, long distance migration between source and reservoir intervals entangles understanding of the tight-gas accumulation mechanism. It is unclear whether producible gas in Jurassic intervals is either from “simple sweet-spots in a continuous accumulation” or “conventionally trapped accumulations in low-permeability reservoir rocks”. To identify the regionally active gas system and characterize the charging pattern, a geochemical study was performed by interpreting the gas molecular and carbon isotope compositions in Jurassic and conducting gas–source correlations as well as gas migration distance calculation with the relationship among δ13C1 vs. Ro vs. H (burial depth). Research results indicate that the Jurassic tight gases in Majing-Shifang areas are coal-derived dry gases generated by the primary cracking of kerogen. Gas/source correlation and gas migration distance calculation reveal that gases are mainly sourced from the Upper Triassic humic source rocks (T3 x5, the fifth member of the Xujiahe Formation). Gas accumulations in the Jurassic Penglaizhen Formation were formed with an original vertical migration of about 2–3 km and then a long-distance lateral migration within tight sand layers, which is verified by the decreasing δ13C1 and the general increasing iC4/ nC4 in the Penglaizhen Formation. The Jurassic tight-sandstone reservoirs in Majing-Shifang areas occur in low-porosity and low-permeability reservoir rocks in conventional lithological traps, which are not continuous-type gas accumulations or basin-centered gas systems. The faults in Majing area serve as dominant vertical conducting pathway and the relatively permeable intervals within Jurassic and microfractures play an important role in the development of the conventionally trapped natural gas accumulations.

Physical processes occurring in tight gas reservoirs from Western Canadian Sedimentary Basin: Noble gas signature

Abstract Noble gases have become a powerful tool to constrain the origin of fluids as well as the rates of fluid migration in sedimentary basins. The aim of this study was to apply these tracers to understand the genesis and the evolution of unconventional gas reservoirs, basin-centered gas reservoirs (also called tight-gas reservoirs). A natural laboratory for this study is the methane-rich gas field in Cretaceous tight sands from the Western Canadian Sedimentary Basin (WCSB). The selection of the WCSB was motivated by an easy access to wells that cover an extensive area from deep to shallow parts of the basin, as well as the relatively well documented geology and hydrology of the area. The elemental noble gas signature (He, Ar, Kr and Xe) of natural gas from 18 wells of the basin shows a mixture between the original low content noble gas signature of the hydrocarbon gas (after its charge into the reservoir) and water (trapped in intergranular volumes (IGV)), which is comparatively rich in noble gases. This difference in relative contents can be used to estimate the geographical position of the contact between the gas reservoir and the shallower IGV water. Furthermore, the ‘original’ noble gas signature, which is defined as the noble gases generated in the source, later transferred, and mixed with in situ produced noble gases in the reservoir, is mainly composed of radiogenic isotopes (40Ar and 4He). The comparison of 4He/40Ar ratios with an average value for potential source rocks and reservoir rocks production ratio (estimated with U, Th and K concentrations) allows us to understand how the gas was transferred from the source rock to the reservoir rock. These results, combined with the geological and hydrological knowledge of the WCSB, affords a new method to better understand the dynamics of unconventional gas reservoirs.