Fractured Gas Reservoirs Research Articles

Research on Stress Sensitivity of Fractured Carbonate Reservoirs Based on CT Technology

Fracture aperture change under stress has long been considered as one of primary causes of stress sensitivity of fractured gas reservoirs. However, little is known about the evolution of the morphology of fracture apertures on flow property in loading and unloading cycles. This paper reports a stress sensitivity experiment on carbonate core plugs in which Computed Tomography (CT) technology is applied to visualize and quantitatively evaluate morphological changes to the fracture aperture with respect to confining pressure. Fracture models were obtained at selected confining pressures on which pore-scale flow simulations were performed to estimate the equivalent absolute permeability. The results showed that with the increase of confining pressure from 0 to 0.6 MPa, the fracture aperture and equivalent permeability decreased at a greater gradient than their counterparts after 0.6 MPa. This meant that the rock sample is more stress-sensitive at low effective stress than at high effective stress. On the loading path, an exponential fitting was found to fit well between the effective confining pressure and the calculated permeability. On the unloading path, the relationship is found partially reversible, which can evidently be attributed to plastic deformation of the fracture as observed in CT images.

An improved model for predicting elemental sulphur saturation in sour gas reservoir with incidence of reservoir compaction

Elemental sulphur which is originally soluble in gas phase in the reservoir should precipitate from the gas phase after exceeding saturation state and deposit at pore spaces and throat sequentially resulting in porosity and permeability loss. Over several decades, modelling elemental sulphur deposition around the wellbore are mainly focused on the gas reservoir and were based on Darcy flow. Few recent studies have shown models that capable for predicting elemental sulphur deposition considered non-Darcy flow, variations in gas properties with pressure change as well as permeability reduction caused by compaction. It therefore follows that if compaction causes a reduction in the permeability of the reservoir as well as reduction in its porosity, then porosity damage function induced by compaction becomes a crucial factor needed to be incorporated into the existing models to adequately predict sulphur saturation. This study is concerned with developing an accurate model for predicting elemental sulphur saturation in the fractured reservoir by exploring the functional relationship between compaction and elemental sulphur deposition over time. The result obtained from newly improved model is at variance with that obtained from Guo et al. model. This variance may not be unconnected with the fact that the rate of sulphur deposition seemed to have been underestimated by Guo et al. model. The refined model is more accurate and practical in predicting sulphur deposition in fractured sour gas reservoir as it leads to a faster rate of sulphur deposition.

Characteristics of transient production rate performance of horizontal well in fractured tight gas reservoirs with stress-sensitivity effect

Interest in tight gas reservoirs (TGR) has quickly spread worldwide. Most researches on the permeability stress-sensitivity of tight gas reservoirs mainly concentrated on experimental approach, physical modeling or pressure behavior analysis, while transient production rate performance does not attract much attention. This study developed a dual-porosity model of a horizontal well in fractured tight gas reservoirs considering the stress-sensitivity effect. The solution methods include variable substitution, perturbation technique, Laplace transformation, Sturm-Liouville eigenvalue theory, orthogonal transformation and numerical inversion. The results showed that the production rate decreases with the increasing of permeability modulus and the derivative curve will be warped up during the whole system late radial flow stage. The influences of other parameters are also analyzed. The work undertaken here has both theoretical and practical significance in predicting production performance and evaluating underground fluid transport in such formations.

Production data analysis for dual-porosity gas/liquid systems: A density-based approach

Production data analysis impacts assets value and financial decisions significantly. Naturally fractured reservoirs exist widely around the world. A common method to represent naturally fractured reservoirs is dual-porosity model. Intrinsic characteristics of dual-porosity systems and their unique rate-transient profile require models able to capture well behavior and to achieve production data analysis, which is a proven difficulty for dual-porosity gas system and not completely solved. Moreover, past studies on dual-porosity systems assume constant bottom-hole pressure (BHP) or constant rate production, which impose significant constraint to production data analysis.Recently a density-based approach for analyzing production data was proposed for single-porosity system, which has been proven to successfully describe gas well behavior under boundary-dominated flow (BDF). Using depletion-driven parameters, λ and β, this state-of-the-art approach circumvents pseudo time. It was then extended to variable-pressure-drawdown/variable-rate gas systems and proven successful.In this study, we adopt a rigorously derived interporosity flow equation for gas, which captures viscosity-compressibility change of matrix outflow. Based on that, a density-based, rescaled exponential model for variable pressure drawdown/variable rate production was developed for dual-porosity gas system. Also, we explore straight-line analysis for convenient prediction of OGIP and production rate. The density-based model is tested in a variety of scenarios to showcase its validity.Moreover, based on Warren and Root model, a density-based exponential model for variable pressure drawdown/variable rate in dual-porosity liquid system is proposed and fully verified. A straight-line analysis is proposed to enable explicit OOIP prediction and convenient future production calculation. Moreover, a convenient double-exponential decline model under constant BHP is developed for liquid.To summarize our work, we developed rate-transient analysis method for two types of reservoirs-naturally fractured gas reservoir and naturally fractured oil reservoirs-producing at arbitrary type of production scenario in boundary-dominated-flow stage. The proposed method can evaluate reserve in a convenient and accurate manner. Moreover, the method to predict production using the theory is also provided. An explicit equation correlating dimensionless production rate and dimensionless time is also developed for dual-porosity liquid system producing at constant bottomhole pressure in both early transient stage and boundary-dominated-flow stage.

Damage evaluation on oil-based drill-in fluids for ultra-deep fractured tight sandstone gas reservoirs

In order to explore the damage mechanisms and improve the method to evaluate and optimize the performance of formation damage control of oil-based drill-in fluids, this paper took an ultra-deep fractured tight gas reservoir in piedmont configuration, located in the Cretaceous Bashijiqike Fm of the Tarim Basin, as an example. First, evaluation experiments were conducted on the filtrate invasion, the dynamic damage of oil-based drill-in fluids and the loading capacity of filter cakes. Meanwhile, the evaluating methods were optimized for the formation damage control effect of oil-based drill-in fluids in laboratory: pre-processing drill-in fluids before grading analysis; using the dynamic damage method to simulate the damage process for evaluating the percentage of regained permeability; and evaluating the loading capacity of filter cakes. The experimental results show that (1) oil phase trapping damage and solid phase invasion are the main formation damage types; (2) the damage degree of filtrate is the strongest on the matrix; and (3) the dynamic damage degree of oil-based drill-in fluids reaches medium strong to strong on fractures and filter cakes show a good sealing capacity for the fractures less than 100 μm. In conclusion, the filter cakes' loading capacity should be first guaranteed, and both percentage of regained permeability and liquid trapping damage degree should be both considered in the oil-based drill-in fluids prepared for those ultra-deep fractured tight sandstone gas reservoirs.

The material balance equation for fractured vuggy gas reservoirs with bottom water-drive combining stress and gravity effects

Compared with conventional porous-water-drive gas reservoirs, calculating the reserve of a fractured vuggy with water driving is a more difficult and challenging task because of its complex matrix types (matrix, fracture and cavity) and strong rock compressibility. Based on the principles of mass conservation, the material balance equation (MBE) for a fractured vuggy gas reservoir with bottom-water driving is established, and the effects of stress sensitivity and gravity segregation are both considered in the proposed model. The original gas in place (OGIP) and the distribution of the reserve in matrix, fracture and cavity can be determined with the proposed MBE. To test the validity of the model, a depletion test simulating the depleting process of fractured vuggy water-drive gas reservoirs and permeability stress sensitivity experiments with actual full-diameter cores under reservoir conditions are conducted. Then, validation and analysis of the model are compared with the experimental data. It is observed that the water production rate shows a stepped increasing trend instead of a gradually increasing trend during the depletion test. The reserve calculated with the proposed model has the lowest error (1.68%) compared with the experimental data, in which the reserve in the cavity is dominant. Thus, gravity and stress should not be neglected when calculating the reserve of a fractured vuggy gas reservoir with bottom water driving; otherwise, a lower accuracy would be introduced.

Recovery Efficiency in Hydraulically Fractured Shale Gas Reservoirs

At the end of 2015 the U.S. held 5.6% or approximately 369 Tcf of worldwide conventional natural gas proved reserves (British Petroleum Company, 2016, “BP Statistical Review of World Energy June 2016,” British Petroleum Co., London). If unconventional gas sources are considered, natural gas reserves rise steeply to 2276 Tcf. Shale gas alone accounts for approximately 750 Tcf of the technically recoverable gas reserves in the U.S. (U.S. Energy Information Administration, 2011, “Review of Emerging Resources: U.S. Shale Gas and Shale Oil plays,” U.S. Department of Energy, Washington, DC). However, this represents only a very small fraction of the gas associated with shale formations and is indicative of current technological limits. This manuscript addresses the question of recovery efficiency/recovery factor (RF) in fractured gas shales. Predictions of gas RF in fractured shale gas reservoirs are presented as a function of operating conditions, non-Darcy flow, gas slippage, proppant crushing, and proppant diagenesis. Recovery factors are simulated using a fully implicit, three-dimensional, two-phase, dual-porosity finite difference model that was developed specifically for this purpose. The results presented in this article provide clear insight into the range of recovery factors one can expect from a fractured shale gas formation, the impact that operation procedures and other phenomena have on these recovery factors, and the efficiency or inefficiency of contemporary shale gas production technology.

Found Different Attitude Fracture Characteristics of the NMR Curve by Application of 3D Printing Samples

Nuclear magnetic resonance (NMR) has many advantages, such as little testing time, no harm to rock specimen, and is widely used in the measurement of reservoir pore structure. 3D printing also has many advantages, such as repeating the printing the same attributes samples, forming sample by known rock pore structure, adding different pores or fractures to sample. For the study of fractured reservoir provides a new train of thought by combining NMR and 3D printing. Nuclear magnetic core analysis is an important work in the study of core, using a T2 spectrum at a certain echo time can also be found in the core fractures. The study, by CT scans to establish reservoir pore structure, based on the basic of adding different attitude fracture forming four fracture characteristics of rock sample, using 3D printing for solid sample, through the analysis of the nuclear magnetic resonance (NMR) of these sample, get the response characteristics of fracture characteristics on the T2 curve, the quantitative calculation of fracture porosity of rock sample, the result accord with to establish the model of fracture porosity is very good. For the study of fractured oil and gas reservoir development the new field.

Adaptive implicit finite element methods for multicomponent compressible flow in heterogeneous and fractured porous media

AbstractThis work presents adaptive implicit first‐order and second‐order discontinuous Galerkin (DG) methods for the transport of multicomponent compressible fluids in heterogeneous and fractured porous media, discretized by triangular, quadrilateral, and hexahedral grids. The adaptive implicit method (AIM) combines the advantages of purely explicit or implicit methods (in time). In grid cells with high fluxes or low pore volumes, the transport update is done implicitly to alleviate the Courant‐Friedrichs‐Lewy (CFL) time step constraints of the conditionally stable explicit approach. Grid cells with a large CFL condition are updated explicitly. Combined, this allows higher efficiency than explicit methods, but it reduces the “penalty” of implicit methods, which exhibit high numerical dispersion and are more computationally and storage expensive per time step. The advantages of AIM are modest for uniform grids and rock properties. However, in heterogeneous or fractured reservoirs explicit methods may become impractical, while a fully implicit approach introduces unnecessary numerical dispersion and is overkill for low‐permeability layers and matrix blocks. In such applications, AIM is shown to be significantly more efficient and accurate. The division between explicit and implicit grid cells is made adaptively in space and time. This allows for a high level of explicitness and can also adapt to high fluxes caused by, e.g., viscous and gravitational flow instabilities. Numerical examples demonstrate the powerful features of AIM to model, e.g., solute transport, carbon sequestration in saline aquifers, and miscible gas injection in fractured oil and gas reservoirs.

裂缝型潜山油气藏地质导向建模方法与应用

裂缝型潜山油气藏地质导向建模方法与应用

Integrated techniques for rapid and highly-efficient development and production of ultra-deep tight sand gas reservoirs of Keshen 8 Block in the Tarim Basin

The unusually ultra-deep and ultra-high-pressure gas reservoirs in the Keshen 8 Block on the Kelasu structural belt of the Tarim Basin are also featured by high temperature, well-developed fault fissures, huge thickness, tight matrix, complex oil–water distribution, etc., which brings about great difficulties to reserves evaluation and further development. In view of this, an overall study was made on the fine description of reservoir fractures and their seepage mechanism, technical problems were being tackled on seismic data processing and interpretation of complex and high & steep structural zones, optimal development design, safe & rapid drilling and completion wells, reservoir stimulation, dynamic monitoring, etc. to promote the development level of such ultra-deep tight gas reservoirs, and 22 complete sets of specific techniques were formulated in the fields of high-efficiency well spacing, safe and fast drilling, recovery enhancement by well completion transformation, efficient development of optimization design, and so on. Through the technical progress and innovative management of integrated exploration & development, reserves evaluation and productivity construction have been completed on the Keshen 8 Block in the last three years of the 12th Five-Year Plan period (2011–2015), as a result, rapid and high-efficiency productivity construction is realized, and a new area is explored in the development of ultra-deep and ultra-high-pressure fractured tight sand gas reservoirs. This study is of great reference to the development of similar gas reservoirs at home and abroad.

Numerical simulation study of shale gas reservoir with stress-dependent fracture conductivity using multiscale discrete fracture network model

ABSTRACTThe exploitation of shale gas has increasingly become the focus of worldwide energy industry. Due to the existence of natural/hydraulic fractures, most of the shale gas reservoirs exhibit high degree of heterogeneity and complexity which leads to the stress-dependent fracture conductivity of shale gas reservoir. Discrete fracture network (DFN) model is adopted in this research since the conventional continuum model cannot meet the numerical simulation requirements of fractured shale gas reservoir. A series of experiments about the fracture properties stress-dependent have been conducted on some shale core samples, the stress-dependent fracture conductivity correlation is selected and incorporated into the mathematical model to characterize the reduction of fracture conductivity potential with the reservoir pressure drop. The DFN model is applied to a shale gas reservoir with fracture network to study the effect of the stress-dependent fracture conductivity on the shale gas well performance. The results show that the effect of fracture conductivity reduction with pressure drop on the shale gas well performance depends on both the initial fracture conductivity and matrix permeability. The complex interactions between the fracture and matrix permeability should be considered when select the appropriate size of proppants for fracturing.

Capacity expansion analysis of UGSs rebuilt from low-permeability fractured gas reservoirs with CO2 as cushion gas

The techniques of pressurized mining and hydraulic fracturing are often used to improve gas well productivity at the later development stage of low-permeability carbonate gas reservoirs, but reservoirs are watered out and a great number of micro fractures are produced. Therefore, one of the key factors for underground gas storages (UGS) rebuilt from low-permeability fractured gas reservoirs with CO2 as the cushion gas is how to expand storage capacity effectively by injecting CO2 to displace water and to develop control strategies for the stable migration of gas–water interface. In this paper, a mathematical model was established to simulate the gas–water flow when CO2 was injected into dual porosity reservoirs to displace water. Then, the gas–water interface migration rules while CO2 was injected in the peripheral gas wells for water displacement were analyzed with one domestic UGS rebuilt from fractured gas reservoirs as the research object. And finally, discussion was made on how CO2 dissolution, bottom hole flowing pressure (BHFP), CO2 injection rate and micro fracture parameters affect the stability of gas–water interface in the process of storage capacity expansion. It is shown that the speed of capacity expansion reaches the maximum value at the fifth cycle and then decreases gradually when UGS capacity is expanded in the pattern of more injection and less withdrawal. Gas–water interface during UGS capacity expansion is made stable due to that the solubility of CO2 in water varies with the reservoir pressure. When the UGS capacity is expanded at constant BHFP and the flow rate, the expansion speed can be increased effectively by increasing the BHFP and the injection flow rate of gas wells in the central areas appropriately. In the reservoir areas with high permeability and fracture-matrix permeability ratio, the injection flow rate should be reduced properly to prevent gas–water interface fingering caused by a high-speed flow. Furthermore, it is necessary to monitor strictly the migration of gas–water interface by using observation wells to prevent gas escape through the edge water or water breakthrough at high-permeability zones. These research results provide a technical and theoretical support for water displacement and capacity expansion of UGS rebuilt from low-permeability fractured gas reservoirs with CO2 as the cushion gas.

Production performance of horizontal wells with dendritic-like hydraulic fractures in tight gas reservoirs

Nowadays horizontal wells, combined with hydraulic fracturing technology, have been widely used to produce tight gas at an economic rate. The production performance of the horizontal well can be predicted by analytical or numerical models. In most models, the horizontal wells are assumed to be fractured by bi-wing fractures. However, recent micro-seismic measurements depict a dendritic-like morphology of hydraulic fractures in tight gas reservoirs. This indicates the conventional fracture models are sometimes inapplicable for tight gas simulation.In this paper, a modified off-center well model was coupled in the discrete fracture model (DFM) to predict the production performance of dendritic-like stimulated horizontal wells. Finite volume method was used to discretize the partial differential equations, and the linearized equation system was solved iteratively in a fully implicit scheme. The off-center well model was verified against ECLIPSE. A field case of multi-stage fractured horizontal well from a shale gas reservoir was studied.In addition, the effects of some fracture geometric parameters (e.g., fracture angle, fracture asymmetry and fracture branch number) on well production were investigated in detail. Results show that fracture angle has high relevance to the production performance in that cumulative production tends to be higher with more evenly distributed angles. Fracture asymmetry seems to have little influence upon the production. Fracture branch number has a strong influence on enhancing gas production, but the influence becomes weaker with increasing branch number. This paper provides us a better understanding of dendritic-like fractured gas reservoirs.

A Numerical Study of Thermal-Hydraulic-Mechanical Simulation With Application of Thermal Recovery in Fractured Shale-Gas Reservoirs

Summary Shale gas is playing an important role in transforming global energy markets with increasing demands for cleaner energy in the future. One major difference in shale-gas reservoirs is that a considerable amount of gas is adsorbed. Up to 85% of the total gas within shale may be found adsorbed on clay and kerogen. How much of the adsorbed gas can be produced has a significant effect on ultimate recovery. Even with improving fracturing and horizontal-well technologies, the average gas-recovery factors in US shale plays are only approximately 30% with primary depletion. Adsorbed gas can be desorbed by lowering pressure and raising temperature and reservoir-flow capacity can be also influenced by temperature, so there is a big prize to be claimed by use of thermal-stimulation techniques to enhance recovery. To date, not much work has been done on thermal stimulation of shale-gas reservoirs. In this study, we present general formulations to simulate gas production in fractured shale-gas reservoirs for the first time, with fully coupled thermal-hydraulic-mechanical (THM) properties. The unified-shale-gas-reservoir model developed in this study enables us to investigate multiphysics phenomena in shale-gas formations. Thermal stimulation of fractured gas reservoirs by heating propped fractures is proposed and investigated. This study provides some fundamental insight into real-gas flow in nanopore space and gas-adsorption/desorption behavior in fractured gas shales under various in-situ conditions, and sets a foundation for future research efforts in the area of enhanced recovery of shale-gas reservoirs. We find that thermal stimulation of shale-gas reservoirs has the potential to enhance recovery significantly by enhancing the overall flow capacity and releasing adsorbed gas that cannot be recovered by primary depletion. However, the process may be hampered by the low heat transfer rate if only the surfaces of hydraulic fractures are heated.

Production forecast of fractured shale gas reservoir considering multi-scale gas flow

The shale gas experiences many different spatial scales during its flow in the reservoir, which will engender different flow mechanisms. In order to accurately simulate the production performance of shale gas well, it is essential to establish a multi-continuum model for shale gas reservoir. Based on the geometrical scenario of multistage horizontal well fracturing, this paper builds up a triple-continuum model incorporating three systems: matrix with extremely low permeability, less permeable natural fractures and highly permeable hydraulic fractures. This numerical model employs Langmuir adsorption equation to present the influence of desorption gas in matrix and considers the Klinkenberg effect in matrix and natural fractures by adjusting the apparent permeability. The solution of this model is achieved using implicit scheme. Eventually, this model is applied on the single well production situation in a synthetic reservoir, production decline curves and cumulative production curves are obtained, then the sensitivity analysis is made on various kinds of parameters; thus, the influences of these parameters on production rate are obtained: The gas rate will rise with the increase in hydraulic fracture half-length, meshing size, Langmuir volume and Langmuir pressure, but with the decrease in hydraulic fracture spacing.

Study on sulfur deposition damage model of fractured gas reservoirs with high-content H 2 S

Due to extreme poison, strong corrosion, and complex precipitation and deposition of H2S in the reservoir, it is very difficult and risky to investigate and explore drilling, completion, production and gas transportation. In the course of production of fractured gas reservoir with high H2S content, formation pressure falls continually, which lead to decline of solubility of sulfur particles in gas phase. Sulfur particles which dissolve in gas phase originally in the formation should precipitate from gas phase after running up to saturation state and deposit at pore space and throat, sequentially resulting in formation porosity and permeability reduction. At present, the researches of sulfur deposition are mainly focused on the conventional gas reservoirs and sulfur deposition in the near wellbore region is generally estimated using Roberts' model. However, most of the gas reservoirs with high-content H2S are fractured gas reservoirs, classical damage model is no longer applicable to fractured gas reservoirs with high H2S content. In the present study, a sulfur deposition damage model is established. The refined model, based on non-Darcy flow, takes into consideration the effects of sulfur deposition, variation in gas properties and fracture. In addition, the effect of gas well production rate on formation permeability is also studied. The results show that formation permeability decreases with fracture aperture and gas well production rate increasing. The bigger gas well production rate is, the quicker sulfur precipitates. The sulfur deposition of fractured gas reservoir with high-content H2S is mainly in the near wellbore zone, and the fracture aperture has a significant impact on the formation permeability in the near wellbore zone.

Decline curve analysis using a pseudo-pressure-based interporosity flow equation for naturally fractured gas reservoirs

Significant amounts of oil and gas are trapped in naturally fractured reservoirs, a phenomenon which has attracted growing attention as production from unconventional reservoirs starts to outpace production from conventional sources. Traditionally, the dual-porosity model has been used in modeling naturally fractured reservoirs. In a dual-porosity model, fluid flows through the fracture system in the reservoir, while matrix blocks are segregated by the fractures and act as fluid sources for them. This model was originally developed for liquid flow in naturally fractured systems and it is therefore inadequate for capturing pressure-dependent effects such as viscosity–compressibility changes in gas systems in its original form. This study presents a rigorous derivation of a gas interporosity flow equation that accounts for the effects of such pressure-sensitive properties. A numerical simulator using the gas interporosity flow equation is built and demonstrates a significant difference in system response from that of a simulator implementing a liquid-form interporosity flow equation. For this reason, rigorous modeling of interporosity flow is considered essential to decline curve analysis for naturally fractured gas reservoirs. In this study, we also show that the use of the proposed gas interporosity flow equation eliminates late-time decline discrepancies and enables rigorous decline curve analysis. The applicability of density-based approach in dual-porosity gas systems is investigated, and the approach reveals that gas production can be forecast in terms of a rescaled liquid solution that uses depletion-driven parameters, λ and β. Application of this approach demonstrated that, at the second decline stage, gas production profile shifted from its liquid counterpart is identical to gas numerical responses with gas interporosity flow equation in effects. The production rates from the pseudo-function approach and those from simulations implementing the gas interporosity flow equation for the synthetic reservoirs are compared against each other, which demonstrated good matches during decline.

Impact of micro- and macro-scale consistent flows on well performance in fractured shale gas reservoirs

Shale gas revolution comes from the skillful combination of horizontal drilling and hydraulic fracturing technology that can create a fractured gas reservoir for gas production. The well performance in the fractured shale gas reservoir is significantly impacted by the complicated gas flow regimes in both fracture network and shale matrix. The consistency between the macro-flow in fracture network and the micro-flow in shale matrix determines the gas production curve, thus being a key issue to gas well design. This paper proposes a numerical model to investigate the impact of micro- and macro-scale consistent gas flows on well performance in fractured shale gas reservoirs. In this numerical model, the macro-scale gas flow follows the Darcy law in the fracture network and the micro-flow in the shale matrix is described by a diffusion-controlled gas transport model. Two apparent diffusion coefficients or models are then obtained. They incorporate viscous flow with slip boundary, molecular diffusion (i.e. molecular self-diffusion), Knudsen diffusion, and surface diffusion in the adsorption layer. The performances of these two diffusion models for the gas transport within shale matrix are investigated and compared with two apparent permeability models proposed by Singh and Javadpour (2013) and Darabi et al. (2012). Furthermore, the pressure-dependent anisotropy of fracture permeability and compressibility is incorporated into the numerical model. This numerical model is verified by an analytical solution and history matching for a Barnett shale gas well. Finally, a fractured gas reservoir with different scenarios is numerically simulated and the shapes of production curves are analyzed through parametric study. It is found that the enhancement of gas recovery efficiency and the life of a shale gas well can be effectively designed if the consistency of micro- and macro-flows can be well designed.

A semi-analytical mathematical model for predicting well performance of a multistage hydraulically fractured horizontal well in naturally fractured tight sandstone gas reservoir

Multiple fractured horizontal well (MFHW) is one of the key technologies to exploit low permeability reservoirs. The accuracy of productivity evaluation after fracturing not only affects the effectiveness of fracturing treatment, but also affects the optimum design of parameters in horizontal wells. This paper is the first investigation into the semi-analytical mathematical modeling for gas productivity calculation of multi-staged horizontal wells in fractured tight sandstone gas reservoirs that emphatically considers the impact of flow in fracture network (natural fracture system). Herein, a production forecast model of complex hydraulic fractures was created where the impact of nature fractures was simulated, and a semi-analytical solution was obtained by using Gaussian elimination method. As extension of historical work, this novel model could be applicable to more actual conditions such as fractures at arbitrary angles and unequal, asymmetric fractures.In the subsequent work, a numerical simulation of a simple conceptual model has been conducted, which validated the accuracy of this novel model. Then a real case application was successfully implemented. The modeling calculation result and actual production data of well X in Surig gas field is in good accordance. Besides, the impact of reservoir parameters upon production and morphology optimization were specifically analyzed. Using this new model, the production performance decline curves were drawn up based on computing results and were thoroughly analyzed for the sensitivity of reservoir parameters, especially the natural fractures. As presented in the performance curves, the post-frac production is greatly influenced by the change of permeability in fracture network, also confirming the applicability of this new model in fractured tight sandstone gas reservoirs.