Tight Gas Sands Research Articles

Pressure Transient and Production Analysis of Fractured Vertical Wells in Tight Sand Gas Reservoirs Considering Threshold Pressure Gradient, Phase-Change Phenomenon, and Stress Sensitivity

The productivity and pressure response of the tight sand gas wells are influenced by multiple flow mechanisms, such as threshold pressure gradient, phase-change phenomena, and stress sensitivity. Understanding the sensitivity of these factors is crucial for the effective development of tight sand gas reservoirs. This study aims to clarify the sensitivity of various factors affecting the productivity and pressure response of tight sand gas wells. Based on the percolation theory of tight sand gas reservoirs, we considered stress sensitivity, threshold pressure gradient, and phase-change phenomena to derive an unsteady mathematical model of a fractured well with an infinite boundary, and a point source solution was obtained. The proposed model was solved using series function properties, variable substitution, perturbation technique, Poisson superposition formula, Laplace transform, and numerical inversion. The influence of several important parameters on pressure response and productivity is discussed in detail. The results show that the threshold pressure gradient, stress sensitivity, and skin factor significantly impact gas well production and pressure response, while the wellbore storage effect and phase-change effect primarily affect the initial production and pressure response, having little effect on the cumulative gas production. The proposed model can estimate the influence of the threshold pressure gradient and stress sensitivity on productivity and pressure, providing a guide for the development of technical measures for fractured wells in tight sand gas reservoirs.

Blasingame production decline curve analysis for fractured tight sand gas wells based on embedded discrete fracture model

Blasingame production decline curve analysis (PDCA) is crucial for extracting natural gas from fractured tight sandstone reservoirs (FTSRs). The natural gas flow in FTSRs is complex due to high-velocity non-Darcy (hvnD) flow, threshold pressure gradient (TPG), and stress sensitivity of reservoirs. These factors pose a challenge in solving nonlinear equations. In this paper, we establish a mathematical model for the flow of natural gas in FTSRs. The fracture is characterized by a hvnD flow coupled using an embedded discrete fracture model (EDFM). The gas flow in the matrix is coupled with the TPG. Stress sensitivity has been considered in both fractures and matrix. The finite volume method (FVM) was employed to discretize and solve the nonlinear equations in the model. The pressure-normalized rate algorithm and gas flow model were used to present a Blasingame production decline curve for fractured horizontal wells in FTSRs. The Blasingame production decline curve can be used to identify natural gas flow regimes, matrix petrophysical properties, and fracture parameters. The effect of the hvnD flow in fractures, the lvnD flow in the matrix (TPG), stress sensitivity, fracture parameters, and production schedule on the Blasingame production decline curve and pressure profile are discussed in detail. This study provides scientific and theoretical support for predicting gas wells performance and the gas production decline law in FTSRs.

3D reservoir characterization of the Mangahewa Formation, Mangahewa Field, Taranaki Basin, New Zealand

The Mangahewa Formation is the primary reservoir target in the Mangahewa Field in the Taranaki Basin, New Zealand. This formation is distinguished by its marginal marine substantial tight-sand reservoir, having thickness exceeding 800 m. The aim of this study is to assess the reservoir properties of the Mangahewa Formation through 3D reservoir modeling, employing 3D seismic data, core data, and well data from the Mangahewa Field. Utilizing variance attributes, the faults and horizons have been identified successfully within the field. The majority of the interpreted faults exhibit dip angles exceeding 60°, with a maximum displacement of 118 m. To detect direct hydrocarbon indicators, root-mean-square amplitude seismic attribute, envelope, and generalized spectral decomposition techniques have been employed. Subsequently, four lithofacies, comprising 78.3% sandstone, 9.2% siltstone, 9.5% claystone, and 3.0% coal have been established by utilizing the Sequential Indicator Simulation (SIS) algorithm to create a lithofacies model. A property model has been generated using the Sequential Gaussian Simulation (SGS) algorithm. Petrophysical evaluation indicates that the Mangahewa Formation exhibits reservoir qualities ranging from fair to good, with porosity levels between 8% and 11%, permeability averaging up to 10 mD, variable shale volumes, and hydrocarbon saturation in the range of 40%–50%. This study's methodologies and findings can serve as a valuable foundation for similar investigations in other tight-sand gas fields located in different regions.

Unconventional Reservoir Characterization and Formation Evaluation: A Case Study of a Tight Sandstone Reservoir in West Africa

Unconventional reservoirs, including gas shales and tight gas sands, have gained prominence in the energy sector due to technological advancements and escalating energy demands. The oil industry is eagerly refining techniques to decipher these reservoirs, aiming to reduce data collection costs and uncertainties in reserve estimations. Characteristically, tight reservoirs exhibit low matrix porosity and ultra-low permeability, necessitating artificial stimulation for enhanced production. The efficacy of the stimulation hinges on the organic material distribution, the rock’s mechanical attributes, and the prevailing stress field. Comprehensive petrophysical analysis, integrating standard and specialized logs, core analyses, and dynamic data, is pivotal for a nuanced understanding of these reservoirs. This ensures a reduction in prediction uncertainties, with parameters like shale volume, porosity, and permeability being vital. This article delves into an intricate petrophysical evaluation of the Nene field, a West African unconventional reservoir. It underscores the geological intricacies of the field, the pivotal role of data acquisition, and introduces avant-garde methodologies for depth matching, rock typing, and the estimation of permeability. This research highlights the significance of unconventional reservoir exploration in today’s energy milieu, offering a granular understanding of the Nene field’s geological challenges and proffering a blueprint for analogous future endeavours in unconventional reservoirs.

Petroleum geology of conventional and unconventional resources: Introduction

Understanding reservoir, source, seal, migration pathways and trap characterization is the first step towards better energy resource exploitation. Several studies have been conducted in recent decades on the reservoir characteristics of conventional resources. Unconventional resources, on the other hand, have received more attention as alternative future energy solutions to depleted conventional resources. Drilling, exploration, development, and production of conventional and unconventional resources pose technical challenges to the energy industry. This special issue attempts to address the most pressing technical challenges in developing conventional reservoirs (such as sandstone and carbonate reservoirs) as well as unconventional energy sources (e.g., shale gas, shale oil, tight gas sand, coal bed methane, geothermal and gas hydrates). The special issue is composed of 21 papers that are classified into six different groups related to the physical and mechanical properties of reservoirs, petroleum geochemistry, petroleum geology, geological modelling, unconventional resource evaluation and conventional reservoir evaluation.

Seepage Model and Pressure Response Characteristics of Non-Orthogonal Multi-Fracture Vertical Wells with Superimposed Sand Body in Tight Gas Reservoirs

Faced with difficulties stemming from the complex interactions between tight gas sand bodies and fractures, when describing and identifying reservoirs, a composite reservoir model was established. By setting the supply boundary to characterize the superposition characteristics of sand bodies, a mathematical model of unstable seepage in fractured vertical wells in tight sandstone gas reservoirs was developed, considering factors such as stress sensitivity, fracture density and fracture symmetry. The seepage law and pressure response characteristics of gas wells in tight sandstone discontinuous reservoirs with stress sensitivity, semi-permeable supply boundary and complex fracture topology were determined, and the reliability of the model was verified. The research results more accurately display the pressure characteristic of a vertical well in the superimposed sand body with complex fractures and provide a more comprehensive model for tight gas production dynamic analysis and well test data analysis, which can more accurately guide the dynamic inversion of reservoir and fracture parameters.

Experimental and EOR Mechanism Study of Water Shutoff Effects on Fractured Tight Sand Gas Reservoirs Using Fuzzy Ball Fluids

In recent years, there has been quite a dispute over the water shutoff effect of fuzzy ball fluids in fractured tight sandstone gas reservoirs. The core issue of this dispute is to try and make fuzzy ball fluid stabilize gas during the water shutoff process for sustainable development. In order to solve this dispute, the Linxing He-2 reservoir matrix core and a core with artificial fractures were used to simulate interlayer water, artificial fractures, and water output channels from the side and bottom. Simulated formation water and nitrogen were used as the two-phase flow phase. The breakthrough pressure of the air and water phases was tested after plugging with fuzzy ball fluid in order to simulate and analyze the water shutoff effect of the fuzzy ball fluid and its ability to achieve air establishment and water control. The results of this study show that for the core matrix, the breakthrough pressure gradient for water and gas varied from 0.200 MPa/cm to 0.210 MPa/cm and 0.015 MPa/cm to 0.025 MPa/cm, and for artificial fractured cores, the breakthrough pressure gradient of water and gas varied from 0.035 MPa/cm to 0.040 MPa/cm and 0.015 MPa/cm to 0.020 MPa/cm. These results prove that fuzzy ball fluid can block small-scale water output channels, such as matrix pores, through the polymer film-forming structure, and plug the artistic cracks and large-scale water output channels of the water flowing into the sides and bottom through the accumulation of a large number of fuzzy balls, which greatly improves the flow resistance of water. The amount of fuzzy ball fluid should be carefully adjusted with consideration of the water output and formation conditions. For large-scale water output channels and side and bottom water shutoff operations, it is recommended that the amount of fuzzy balls be increased along with the number of fuzzy balls in the system in order to increase the breakthrough pressure of water and achieve the stable control of air and water. It is believed that the fuzzy balls would quickly change their shapes to match the sizes of fracture channels to enter into fractured reservoirs and that an active hydrophobic membrane would form on the surface of fractured rocks, with macromolecules and surfactants being dispersed in the fluid system. In addition, the interface between the fuzzy balls is also hydrophobic, which would slow down the flow of water and provide a continuous gas percolating channel after aggregating and entering into the fractures. This increases the persistence of water intruding into the formation and does not affect the percolation of the gas of fractured tight sandstone gas reservoirs. This research is of great significance for the EOR of tight sand gas reservoirs and the sustainable development of oil and gas resources in China.

Pressure transient analysis for multi-stage fractured horizontal wells considering threshold pressure gradient and stress sensitivity in tight sandstone gas reservoirs

Tight sand gas reservoirs are characterized with low porosity and low permeability. The threshold pressure gradient (TPG) and stress sensitivity effect are particularly apparent during gas production in tight sand gas reservoirs, causing the pressure transient analysis (PTA) curves of multi-stage fracturing horizontal wells (MFHWs) in tight sand gas reservoirs to be abnormally upward and making it challenging to match current PTA models. Therefore, in this work, a new PTA model for MFHW considering TPG and stress sensitivity was established. Based on the point source function, a semi-analytical solution of the model could be obtained using the properties of series function, variable substitution, perturbation technique, Poisson superposition formula, Laplace transform, and numerical inversion. Moreover, the effects of TPG, stress sensitivity, well parameters, and fracture parameters on the PTA curves were analyzed. Overall, we believe that the results of this study can guide the pressure transient analysis of MFHWs in tight sand gas reservoirs and provide help for engineers with regard to evaluating the parameters of reservoirs and fractures more accurately.

Quantitative Characterization of Shallow Marine Sediments in Tight Gas Fields of Middle Indus Basin: A Rational Approach of Multiple Rock Physics Diagnostic Models

For the successful discovery and development of tight sand gas reserves, it is necessary to locate sand with certain features. These features must largely include a significant accumulation of hydrocarbons, rock physics models, and mechanical properties. However, the effective representation of such reservoir properties using applicable parameters is challenging due to the complicated heterogeneous structural characteristics of hydrocarbon sand. Rock physics modeling of sandstone reservoirs from the Lower Goru Basin gas fields represents the link between reservoir parameters and seismic properties. Rock physics diagnostic models have been utilized to describe the reservoir sands of two wells inside this Middle Indus Basin, including contact cement, constant cement, and friable sand. The results showed that sorting the grain and coating cement on the grain’s surface both affected the cementation process. According to the models, the cementation levels in the reservoir sands of the two wells ranged from 2% to more than 6%. The rock physics models established in the study would improve the understanding of characteristics for the relatively high Vp/Vs unconsolidated reservoir sands under study. Integrating rock physics models would improve the prediction of reservoir properties from the elastic properties estimated from seismic data. The velocity–porosity and elastic moduli-porosity patterns for the reservoir zones of the two wells are distinct. To generate a rock physics template (RPT) for the Lower Goru sand from the Early Cretaceous period, an approach based on fluid replacement modeling has been chosen. The ratio of P-wave velocity to S-wave velocity (Vp/Vs) and the P-impedance template can detect cap shale, brine sand, and gas-saturated sand with varying water saturation and porosity from wells in the Rehmat and Miano gas fields, both of which have the same shallow marine depositional characteristics. Conventional neutron-density cross-plot analysis matches up quite well with this RPT’s expected detection of water and gas sands.

Beyond conventional approach: hybrid supervised learning and feature selection algorithms for prediction sonic logs - a study in a tight gas sand, North of Oman

Beyond conventional approach: hybrid supervised learning and feature selection algorithms for prediction sonic logs - a study in a tight gas sand, North of Oman

Beyond conventional approach: hybrid supervised learning and feature selection algorithms for prediction sonic logs - a study in a tight gas sand, North of Oman

Beyond conventional approach: hybrid supervised learning and feature selection algorithms for prediction sonic logs - a study in a tight gas sand, North of Oman

Exploring the potential of oil and gas resources in Sichuan Basin with Super Basin Thinking

Based on the contemporary strategy of PetroChina and the “Super Basin Thinking” initiative, we analyze the petroleum system, the remaining oil and gas resource distribution, and the Super Basin development scheme in the Sichuan Basin with the aim of unlocking its full resource potential. We conclude that, (1) The three-stage evolution of the Sichuan Basin has resulted in the stereoscopic distribution of hydrocarbon systems dominated by natural gas. The prospecting Nanhua-rift stage gas system is potentially to be found in the ultra-deep part of the basin. The marine-cratonic stage gas system is distributed in the Sinian to Mid-Triassic formations, mainly conventional gas and shale gas resources. The foreland-basin stage tight sand gas and shale oil resources are found in the Upper Triassic–Jurassic formations. Such resource base provides the foundation for the implementation of Super Basin paradigm in the Sichuan Basin. (2) To ensure larger scale hydrocarbon exploration and production, technologies regarding deep to ultra-deep carbonate reservoirs, tight-sand gas, and shale oil are necessarily to be advanced. (3) In order to achieve the full hydrocarbon potential of the Sichuan Basin, pertinent exploration strategies are expected to be proposed with regard to each hydrocarbon system respectively, government and policy supports ought to be strengthened, and new cooperative pattern should be established. Introducing the “Super Basin Thinking” provides references and guidelines for further deployment of hydrocarbon exploration and production in the Sichuan Basin and other developed basins.

The Tight Sand Reservoir Characteristics and Gas Source in Coal Measures: A Case Study of Typical Areas in China

Interbedded sandstones, shales, and coal seams were formed in marine-continental transitional environments of coal measures, and the gas source of its tight sand gas has been uncertain, which hinders the progress of natural gas exploration. This article uses the Longtan tight sand gas in west Guizhou as an example to investigate the reservoir features, gas charging history, and main source rock of tight sand gas by examining thin sections, scanning electron microscopy images, X-ray diffraction results, and the fluid inclusions with burial and thermal histories and noble gas analysis. The Longtan sandstones in this study are classified as litharenites which are characterized by low compositional and textural maturities, and high clay contents, and are distinguished petrographically from conventional sandstones by the extensive existence of micropores and microfractures. The results of the homogenization temperatures of the fluid inclusions show that the Longtan tight sand gas is a single-stage accumulation which occurred during the Late Triassic. Furthermore, through the analysis of the helium and argon isotopes of noble gases, a calculation model was established for determining the shale and coal contributions to the tight sand gas. The research results show that the Longtan tight sand gas mainly belongs to the crust-derived gas, mostly from the Longtan shale-derived contribution and to a lesser extent from the Longtan coal-derived contribution. The measured 40Ar/36Ar values of the Longtan shales and coals are consistent with the forecasted 40Ar/36Ar values from the calculation model, demonstrating that the model is viable to calculate the source rock contribution to the tight sand gas. Therefore, the Longtan shales as main source rocks can generate hydrocarbons to charge neighboring tight sandstones to form tight gas accumulation in the Longtan Formation, which provides an opportunity for tight gas development in west Guizhou.

Study on the Stimulation Effectiveness Evaluation of Large-Scale Hydraulic Fracturing Simulation Experiment Based on Optical Scanning Technology

Summary Unconventional reservoirs such as gas shales and tight gas sands require technology-based solutions for optimum development because of the undeveloped matrix pores and poor permeability. Hydraulic fracturing is one of the most critical technologies. The quantitative characterization of hydraulic fractures is of great significance to the stimulation evaluation of the reservoir, but there is still a lack of fine, effective and systematic evaluation methods. 3D optical scanning technology is widely used in the quantitative characterization of rock fracture morphology for its advantages of high speed, convenience, high precision, and nondestructive testing. In this study, after the indoor hydraulic-fracturing simulation experiments, 3D optical scanning was used to visualize the fracture network. On this basis, two aspects of quantitative evaluation methods for stimulation effectiveness were established, including: (1) evaluating the local conductivity (permeability) of different fractures by cutting hydraulic-fracturing samples. Then combining local conductivity of different fractures with the overall stimulated reservoir area, which could be more reasonable to evaluate the stimulation scope of the reservoir; (2) calculating the fractal dimension (FD) of the 3D spatial structure based on the point-cloud processing, which could directly reflect the complexity of the fracture network. Finally, a new evaluation index for stimulation (Es) was established to comprehensively assess the stimulation effectiveness of the reservoir, which was applied and verified through the indoor fracturing simulation experiments of tight sandstone from the Ordos Basin, China.

Gas and water distribution in the tight gas sands of the northwestern daniudi gas field, ordos basin, China: Impact of the shale barrier

The production of gas from the Upper Paleozoic tight sands in the Daniudi gas field, Ordos Basin, China, is hindered by a lack of knowledge of the factors controlling water distribution. This study aims to clarify the origin of the water, reduce unwanted water production, and detect probable locations of “sweet spots”. A geological study during field development was conducted in the northwestern region of the gas field by integrating production data with other core, well log, mud log, and geological data. The results showed that the gas and water distribution was apparently related to gas charge, with a close negative correlation identified between the thickness of shale barrier and the cumulative gas production on a per well basis. Therefore, the shale barrier has the significant influence on the fluid distribution in the study area. In addition, the shale barrier was found to play a dual role in hindering gas charge toward the upper reservoir and in sealing trapped gas in the lower reservoir, given the configuration of “gas generation below and gas storage above”. This implies the wax and wane relationship. Insights on the shale barrier’s effect contribute to an alternative strategy of “sweet spot” prediction for resource development in unconventional gas reservoirs, i.e., if improved technologies are currently lacking to discriminate between gas-bearing and water-bearing zones in tight gas sands, the spatial distribution of continuous shale can be predicted with 3D seismic data as an initial step, which is thought to be less difficult. The attempts to detect “sweet spots” should subsequently focus on the local area where the thinner shale barrier exists below the producing zone. This work not only can enrich the theory of hydrocarbon accumulation in the Ordos Basin, but also presents an analogue to tight sand gas for worldwide sedimentary basins.

Unsupervised-learning based self-organizing neural network using multi-component seismic data: Application to Xujiahe tight-sand gas reservoir in China

The tight sandstone reservoirs of the Xujiahe Formation of the Western Sichuan Basin Depression typically exhibit characteristics such as low porosity, low permeability, and strong heterogeneity, resulting in weak seismic response differences between gas and water. In present study, we developed an unsupervised learning gas reservoir prediction method using a self-organizing neural network (SOM) to identify and predict tight-sand gas reservoirs in areas with few or no wells. First, we extracted seismic attributes data and obtained multi-component seismic composite attributes. Then, the multi-component composite attributes were fed into the SOM network for training, obtaining the gas reservoir prediction results. Simultaneously, the designed SOM prediction scheme was also applied to PP-wave and PS-wave seismic data respectively for gas reservoir identification and prediction. The prediction results of the multi-component composite attributes exhibited good correspondence with available gas drilling information, indicating their unique merits in resolving issues pertaining to the deep tight gas sandstone reservoir identification. Finally, based on geological data and drilling information, we evaluated the effectiveness of the prediction results of proposed methods, and predicted favorable exploration areas. Effective implementation contributes substantially to tight-sand gas reservoir identification and prediction in less or even no well area. • Unsupervised learning-based self-organizing neural network. • Delineate a tight-sand gas reservoir using multi-component seismic data. • Gas reservoir identification and prediction in few wells or even no well area.

Characterization of Nanoscale Pores in Tight Gas Sandstones Using Complex Techniques: A Case Study of a Linxing Tight Gas Sandstone Reservoir

Pore structures with rich nanopores and permeability in tight gas reservoirs are poorly understood up to date. Advanced techniques are needed to be employed to accurately characterize pore structures, especially tiny pores which include micron and nanopores. In this study, various experimental techniques such as scanning electron microscopy (SEM), nuclear magnetic resonance (NMR) T 2 , nitrogen adsorption method, and NMR cryoporometry (NMRC) are combined to interrogate the complex pore systems of the tight gas reservoir in the Linxing formation, Ordos Basin, China. Results show that tight gas sandstones are primarily comprised of residual interparticle and clay-dominated pores. Clay and quartz are two dominate minerals while pyrite occupies a nontrivial amount as well. The permeability of tight gas sandstones is very low, exhibiting an extremely poor positive correlation with porosity. While pore types and relative pore contents are more influential factors on the permeability, accurate characterization of pore size distribution is critical for the permeability of tight gas sandstones. Therefore, complementary characterization methods are carried out, indicating that neither small pores with radii < 100 nm (around peak 1 in NMR T 2 distribution) nor large pores with radii > 5 μ m (around peak 3 in NMR T 2 distribution) control the permeability by analyzing the connectivity of the pores in various size ranges, but rather pores averaging approximately 350 ± X nm (around peak 2 in NMR T 2 distribution) have sufficient connectivity to host and transmit hydrocarbons. The pore size of tight gas sandstones is dominated by the clay-rich mineral assemblage. The study shows that the NMRC technique can be a very promising method, especially when referred to as a promising “roadmap” on how to interrogate tight formations such as the tight gas sands or even shale especially for the nanopore characterization.

An Integrated Petrophysical Characterization of a Siliciclastic Tight Gas Reservoir in Neuquén Basin, Western Argentina

The Río Neuquén Field is located between Neuquén and Río Negro provinces, Argentina. Historically, it has been a conventional oil producer, but it was converted to a tight gas producer from deeper reservoirs. The targeted geological formations are Lajas, which is already a known tight gas producer, and the less-known overlaying Punta Rosada Formation, which is the main objective of the current work. Punta Rosada presents a diverse lithology, including shaly intervals separating multiple stacked reservoirs that grade from fine-grained sandstones to conglomerates. The reservoir pressure can change from the normal hydrostatic gradient to up to 50% of overpressure. There is little evidence of movable water. The key well in this study has a comprehensive set of openhole logs, including pulsed-neutron spectroscopy data, and is supported by a full core study over 597 ft. Additionally, data from several offset wells were used, containing sidewall cores and complete sets of electrical logs. This allowed the development of rock-calibrated mineral models, adjusting the clay volume with X-ray diffraction data, porosity, and permeability with core measurements, and linking the log interpretation to dominant pore-throat radius models from MICP Purcell tests. Several water saturation models were tested, attempting to adjust the irreducible water saturation with NMR and Purcell tests at reservoir conditions. As a result, three hydraulic units were defined and characterized, identifying a strong correlation with lithofacies observed in cores and image logs. A cluster analysis model allowed the propagation of the facies to the rest of the wells (50). Finally, lithofacies were distributed in a full-field 3D model, guided by an elastic seismic inversion. In the main key well, in addition to the openhole logs and core data, a casedhole pulsed-neutron log (PNL) was also acquired, which was used to develop algorithms to generate synthetic pseudo-openhole logs such as bulk density and resistivity, integrated with the spectroscopy mineralogical information and other PNL data, to perform the petrophysical evaluation. This enables the option to evaluate wells in contingency situations where openhole logs are not possible or too risky, and also in planned situations to replace the openhole data in infill wells, saving considerable drilling rig time during this field development phase. Additionally, the calibrated casedhole model can be used in old wells. This paper explores the integration of different core and log measurements and explains the development of rock-calibrated petrophysical and rock type models addressing the characterization challenges found in tight gas sand reservoirs. The results of this study will be crucial to optimize the field development.

Impact of input, preservation and dilution on organic matter enrichment in lacustrine rift basin: A case study of lacustrine shale in Dehui Depression of Songliao Basin, NE China

Lacustrine rift basins in Eastern China possess large amounts of petroleum, especially the shale gas and tight sand gas in deep formations, where “sweet spots” are closely related to organic-rich shale intervals. However, the OM enrichment of deep formation shale in lacustrine rift basins and the main controlling factors have not been well-researched in previous studies. The organic matter (OM) enrichment is mainly controlled by the OM input, preservation, and/or dilution. The shales deposited in deep formations of Songliao Basin, including the Jurassic Huoshiling (J3h), Cretaceous Shahezi (K1sh), and Yingcheng (K1yc) formations, are evaluated as fair to excellent source rocks. Taking the shales as an example, the characters and impact of input, preservation, and dilution on OM enrichment in shales are discussed by utilizing the parameters of element concentrations and biomarkers. Results show that the OM sources are mixed sources of aquatic microorganisms and higher plant materials, and the higher plant materials are dominant. The bio-productivity were moderate to high. The paleoclimate was mainly the cold and semi-humid to semi-arid. The lake salinity was fresh-to brackish-water. The redox conditions were sub-reducing to sub-oxidizing. The dilution degree in Yingcheng was the strongest, followed by the Shahezi and Huoshiling. Consequently, the OM enrichment in the J3h shale was called moderate bio-productivity and preservation model; the OM enrichment in the K1sh shale was called high bio-productivity and preservation model; the OM enrichment in the K1yc shale was named high dilution model. This study not only improves the model of OM enrichment but also provide some information for the research of “Deep time” in the Cretaceous of Songliao Basin, guiding the prediction of organic-rich shale distribution in lacustrine rift basin.

Hydraulic Fracturing Tight Reservoirs: Rock Mechanics and Transport Phenomena

Conventional reservoirs have been fracture stimulated using acid fracturing and proppant fracturing.Acid fracturing is performed to improve well productivity in acid-soluble formations such aslimestone, dolomite, and chalk. Hydrochloric acid is generally used to create an etched fracture,which is the main mechanism for maintaining the fracture open during the life of a well. Proppantfracturing is an alternative option that has been applied in carbonaceous and siliceous formations.There is no quantitative method to provide an answer of whether acid fracturing or proppantfracturing is an appropriate stimulation method for a given carbonate formation. How rockmechanics can be applied to decide on what method is more effective? Laboratory experiments havebeen performed to simulate acid etched to study the effect of elastic, plastic and viscoelastic rockbehavior and their effects on fracture conductivity. Comparison of acid vs. proppant fracturingconductivity in carbonate formation is presented.Fracturing low permeability reservoirs is totally different than fracturing tight formations. Thefracture geometry required in low permeability reservoirs need to be planar, conductive andpenetrating deep in the reservoir. Fracture complexity in these reservoirs is to be avoided foroptimum stimulation treatment. However, in fracturing tight formation, a complex fracture networkis desirable for better recovery. Creating multiple fractures in horizontal wells without the use ofmechanical intervention, is becoming essential especially in tight gas reservoirs. We have learnedhow to initiate hydraulic fractures into a specific direction and place as many fractures as desired inhorizontal wells but with casing and perforation. The challenge now is to initiate weak point acrossthe horizontal well such that fracturing fluid will initiate a fracture there. How rock mechanics hasbeen applied to achieve this objective? We are fracturing tight gas sand in harsh environment, atdepth more than 18000 ft, of temperature close to 400 °F, and one can figure out the extreme in-situstresses relevant to this depth.When the reservoir pressure decreases, the elastic displacement in response to the increase ineffective stress will cause natural fractures to close leading to a decline in reservoir productivity.
 The matrix medium feeds the natural tensile fractures which carry the fluids to the wellbore. Thedecline in conductivity with increasing effective stress should follow a logical declining rate tosupport a given production rate. How the concept of effective stress has been applied to understandthe stress-dependent conductivity of various conductive components of a given reservoir? Rockmechanics testing of these stress sensitive reservoirs becomes vital to optimize fracturing tightformations.Economical production from tight reservoirs, including shale gas and shale oil formations, requireshorizontal well drilling and massive proppant hydraulic fracturing stimulation. The stimulationinvolves generating sufficient fractures network or stimulated reservoir volume (SRV), which isachieved by placing optimized stimulation treatments along the horizontal section of wellboresideally drilled from multi-well pads to increase the production rate and ultimate recovery. Hydraulicfracturing in naturally fractured formations is characterized by generating a fractures’ network thatshould be designed for in extremely low permeability of unconventional reservoirs. Fractures shouldextensively reach shale matrix to achieve commercial gas production. Therefore, production rate andultimate recovery depend on the size of the created SRV.The transport phenomena controlling fluid flow through tight formation is no longer sufficient to bemodeled by Darcy’s flow. Diffusion and imbibition are important transport mechanisms. The conceptof osmosis and flow through a semi-permeable membrane component are critical. Additionally,diffusion and a special case of molecular flow due to Knudson effect will be discussed. Conventionalreservoir simulation collapses when trying to simulate fluid flow through tight reservoirs. Numericalstudies on a hydraulically fractured well to simulate the dynamic processes during fracturinginjection, following well shut-in (soaking), and production are discussed.