Hydraulic Fracture Half-length Research Articles

A three-dimensional numerical well-test model for pressure transient analysis in fractured horizontal wells with secondary fractures

During oil and gas reservoir development, multi-stage horizontal wells (MFHWs) and hydraulic fracturing techniques can effectively increase estimated ultimate recovery. However, there still lacks an understanding of the three-dimensional (3D) pressure transient behaviors of multi-stage fractured horizontal wells with secondary fractures. To narrow this gap, a three-dimensional numerical well-test model based on a discrete fracture model and unstructured tetrahedral grids is developed to study the pressure transient behaviors of MFHWs with secondary fractures. The pressure transient solutions of MFHWs with secondary fractures have been demonstrated by model verifications. The results show that the proposed model can accurately capture the complex transient flow around fractures, including early radial flow that is not easily captured by two-dimensional numerical well test models. The proposed model classifies the flow regimes of a MFHW as: wellbore storage and skin effects, early radial flow, bilinear flow, linear flow, elliptical flow, pseudo radial flow, and pseudo-boundary dominated flow. It is found that the fracture geometry has a relatively large effect on the shape of the pressure derivative curve in this work. The hydraulic fracture half-length has the greatest impact on the pressure transient behaviors of the MFHW, followed by fracture height and secondary fracture half-length, as found in this study. Additionally, fracture parameters are evaluated, and actual well testing data are interpreted, taking into account the fracture height. This work is meaningful to understand the three-dimensional pressure transient behaviors of MFHWs with secondary fractures.

Probabilistic estimation of hydraulic fracture half-lengths: validating the Gaussian pressure-transient method with the traditional rate transient analysis-method (Wolfcamp case study)

Despite significant advancements in geomodelling technologies, accurately estimating hydraulic fracture half-length remains a challenging task. This paper introduces a detailed estimation approach using the Gaussian Pressure Transient (GPT) method, which is relatively new. The GPT method is iterative, ensuring fast convergence and providing reliable estimations of hydraulic fracture half-length based on a predetermined hydraulic diffusivity value obtained from Gaussian Decline Curve Analysis (DCA). To validate the GPT results, production data from two case study wells in the Wolfcamp Shale Formation, located in the Midland Basin of West Texas, are utilized alongside the traditional Rate-Transient Analysis (RTA) method. Moreover, the GPT method offers the capability to probabilistically estimate hydraulic fracture half-lengths, presenting two innovative approaches to evaluate the robustness of this newly developed method for both deterministic and probabilistic estimations. The simulation results demonstrate a close correlation between the Gaussian method and micro-seismic fracture half-lengths, with separate confirmation from the classic RTA-method. Through the case studies presented in this paper, the GPT-method showcases its utility in estimating hydraulic fracture half-lengths for two Wolfcamp case study wells, effectively demonstrating the validity and practical applicability of this novel method.

General Optimization Framework of Water Huff-n-Puff Based on Embedded Discrete Fracture Model Technology in Fractured Tight Oil Reservoir: A Case Study of Mazhong Reservoir in the Santanghu Basin in China

Summary Water injection huff-n-puff (WHnP) is currently an important technology to improve the recovery of tight reservoirs. On the one hand, this technology can replenish the formation energy, and on the other hand, it can effectively replace the oil in a tight reservoir. In this paper, the effect of WHnP on cumulative oil production and oil increase rate is simulated and analyzed by comparing depleted development and WHnP scenarios, using numerical simulation methods. A field-scale numerical simulation was modeled based on typical fluid, reservoir, and fracture characteristics of Mazhong tight oil, coupled with geomechanical effects, stress sensitivity, and embedded discrete fractures. The result of different WHnP cycles is studied, and the limiting WHnP cycle is determined to be four cycles. The WHnP efficiency is compared for different permeability scales from 0.005 to 1 md, and it is determined that WHnP at a permeability of 0.01 md resulted in the largest production enhancement. Subsequently, sensitivity studies are conducted using an orthogonal experimental design for six uncertain parameters, including the WHnP cycle, production pressure difference, permeability, natural fracture density, hydraulic fracture half-length, and conductivity. The results show that throughput period and permeability are important parameters affecting cumulative oil production, and permeability and natural fracture density are important parameters affecting oil increase rate. In addition, contour plots of permeability and WHnP cycle, hydraulic fracture half-length, and conductivity are generated. Based on these plots, the optimal conditions with better enhanced recovery results in different WHnP scenarios can be easily determined. This study can better solve the problems encountered in WHnP of tight reservoirs and provide a theoretical basis for stable and efficient development.

A semi-analytical approach to nonlinear multi-scale seepage problem in fractured shale gas reservoirs with uncertain permeability distributions

To investigate the influence of the inhomogeneity and uncertainty of porosity and permeability on gas production, a mathematical model for shale gas nonlinear seepage problem with random distributions of inhomogeneous equivalent porosity and permeability is established. Based on the statistical characteristic of the artificial fracture density distribution and incompletely controllable hydraulic fracturing technology, the random distribution models of continuous inhomogeneous equivalent porosity and permeability are proposed to simulate the uncertainty of the porosity and permeability distribution in SRV. Coupled with multi-scale flow and adsorption effects, a mathematical model of shale gas nonlinear seepage problem is presented to address the inhomogeneity and uncertainty of equivalent porosity and permeability. By Boltzmann transformation and local homogenization approximation, a semi-analytical method and the corresponding explicit iterative scheme are developed.Simulation results match well with field data, which verifies the validity of the presented mathematical model and approach. The morphology of the SRV has significant influence on gas production, followed by the uncertainly of the permeability distribution and the hydraulic fracture half-length. When the horizontal width reaches its maximum in the front part of the macro-fracture zone, shale gas production reaches its peak and increases by 60%. The uncertainty of the permeability distribution is resulted from the deviation of the hydraulic fracture. As the deviation angle increases from 0° to 10°, shale gas production drops by 16%. The greater the gas production, the bigger the drop rate. When the hydraulic fracture half-length is 50 m, gas production reaches its peak, however it drops by 13% if the hydraulic fracture half-length increases to 70 m.

Optimization experimental design of stable production life and estimated ultimate recovery in gaseous compound of hydrogen and carbon from shale reservoir

In this study, a mixed numerical model is established to simulate the production performance of gaseous compound of hydrogen and carbon in shale reservoir. Estimated ultimate recovery (EUR) and stable production life (SPL) of gaseous compound of hydrogen and carbon are affected by reservoir parameters and production control parameters, such as Langmuir pressure, Langmuir volume, critical desorption pressure, fracture half length, permeability in stimulated reservoir volume (SRV) area, bottom hole flow pressure and production of gaseous compound of hydrogen and carbon. Therefore, in the later research, in order to reduce the number of numerical experiments, the orthogonal experimental method is used to optimize the influence of hydrocarbon ERU and SPL, and analyze the main control factors affecting these two indices at the same time. The purpose of this paper is to optimize the production of hydrocarbons by orthogonal experimental method and find the main controlling factors affecting the production of compound of hydrogen and carbon. Two groups of orthogonal experiments were designed to find the best scheme in the process of compound of hydrogen and carbon development. The calculative results show that the output of hydrogen and carbon compounds has a highly significant impact on SPL, Langmuir volume and capability in SRV have a significant impact, and Langmuir pressure Critical destruction pressure and hydraulic fracture half-length had no significant effects.

Calibration of Complex Discrete Fracture Network Using Microseismic Events and Fracture Propagation Modelling with Seamless Reservoir Production Simulation

Abstract During the unconventional reservoir development, a proper modelling of the underground fracture networks and their effects on production is crucial for reservoir development potential and realistic economic analysis. Conventionally, the complex fracture system formed by hydraulic and natural fractures is extremely difficult to capture, let alone to numerically simulate it. Most importantly, the current best solution can only rely on the knowledge of the natural fractures from the geology and geophysics team and hydraulic fractures from the engineering team. Nevertheless, this solution fails to realize the dynamic stress regime variations when fracturing jobs are done within the horizontal wellbore. In this study, a variety of data source and modelling tools is harnessed to delineate a more realistic and representative discrete fracture network (DFN). The first step is to obtain the original natural fractures already depicted from geological and geophysical information and the statistical information regarding the spatial configurations of this DFN. Next, a new set of natural fractures is generated by an in-house natural fracture generator while preserving the spatial characteristics of the original natural fractures at the same time. Then, a combined DFN of the original natural fracture and newly generated natural fractures is accomplished. This combined DFN is then intensity-calibrated by the given microseismic cloud events, especially focusing on the near-wellbore region. Then, a displacement discontinuity method- (DDM-) based in-house hydraulic fracture propagation model is used to generate hydraulic fractures with complex boundaries, honoring the fracturing job logistics from the engineering team. After this step, an ultimate and highly representative DFN can be achieved. By applying this very novel workflow, DFN characterizations of both a single-well scenario and well-pad (3 wells) scenarios have been highly successful. Statistics such as the cluster-wise hydraulic fracture half-length, height, aperture, and numbers of activated/nonactivated natural fractures can be easily presented. Through the powerful numerical method called the embedded discrete fracture model (EDFM), production simulation and stimulated reservoir volume evaluation can be seamlessly studied. Extents of 3D drainage volumes can also be plotted with ease. Overall, a holistic picture regarding the unconventional reservoir’s underground DFN can be reliably depicted, using the proposed workflow.

The Application of Integrated Assisted History Matching and Embedded Discrete Fracture Model Workflow for Well Spacing Optimization in Shale Gas Reservoirs with Complex Natural Fractures

An appropriate well spacing plan is critical for the economic development of shale gas reservoirs. The biggest challenge for well spacing optimization is interpreting the subsurface uncertainties associated with hydraulic and natural fractures. Another challenge is the existence of complex natural fractures. This work applied an integrated well spacing optimization workflow in shale gas reservoirs of the Sichuan Basin in China with both hydraulic and natural fractures. The workflow consists of five components: data preparation, reservoir simulation, estimated ultimate recovery (EUR) analysis, economic calculation, and well spacing optimization. Firstly, the multiple realizations of thirteen uncertain parameters of matrix and fractures, including matrix permeability and porosity, three relative permeability parameters, hydraulic fracture height, half-length, width, conductivity, water saturation, and natural fracture number, length, and conductivity, were captured by the assisted history matching (AHM). The fractures were modeled by the embedded discrete fracture model (EDFM) accurately and efficiently. Then, 84 AHM solutions combining with five well spacing scenarios from 517 ft to 1550 ft would generate 420 simulation cases. After reservoir simulation of these 420 cases, we forecasted the long-term gas production for each well spacing scenario. Gas EUR degradation and well interference would imply the critical well spacing. The net present value (NPV) for all scenarios would be calculated and trained by K -nearest neighbors (KNN) proxy to better understand the relationship between well spacing and NPV. In this study, the optimum well spacing was determined as 793 ft, corresponding with a maximum NPV of 18 million USD, with the contribution of hydraulic fractures and natural fractures.

Comprehensive modeling of multiple transport mechanisms in shale gas reservoir production

A boom in the production of shale gas has recently impacted the world’s energy supply. The hydraulic fracturing technology has been widely used in the development of shale gas reservoirs. Models for accurate reservoir simulation are essential for their economic production. In this paper, a model for shale gas reservoir production is proposed to account for slip flow, Knudsen diffusion, surface diffusion, gas adsorption/desorption, stress dependence of a pore structure, a non-ideal gas effect, and a flow mechanism difference between organic and inorganic content in the shale matrix. This model is implemented in our in-house simulator with a coupled MINC-EDFM approach to study and predict shale gas production behavior. Comprehensive sensitivity studies are performed to analyze the importance of different parameters in shale gas production. These parameters are divided into two categories. The first category includes reservoir data, such as shale matrix porosity, a nanopore radius, an organic/inorganic volume ratio, hydraulic fracture half-length, and fracture spacing. The second category includes parameters relevant to flow mechanisms, such as a non-ideal gas effect, stress dependence, presence of an adsorbed layer as well as a selection of a flow mechanism model. It is found that parameters related to hydraulic fractures impact calculated gas production more than reservoir matrix data. Among the fracturing parameters, hydraulic fracture half-length has a stronger effect than fracture spacing, and among matrix properties, porosity has a larger impact than a nanopore radius or the assumed organic/inorganic content ratio. These results help to optimize a shale gas reservoir production design. In addition, in a synthetic case assuming a 1 nm pore radius, the presence of an adsorbed gas layer has a more tremendous effect compared to the non-ideal gas and stress dependence phenomena. Moreover, the developed simulator with the multiple transport mechanisms can be used to accurately predict shale gas reservoir production. The findings of this study help a better understanding of shale gas flow and can be used to enhance the production of shale gas reservoirs.

A semi-analytical model for investigating the productivity of fractured horizontal wells in tight oil reservoirs with micro-fractures

Combining horizontal drilling with hydraulic fracturing has become a well-established technique to improve well productivity in tight oil reservoirs. The existence of micro-fractures in these reservoirs affects the fluid flow process as well as the productivity. However, current models for evaluating the well performance of fractured horizontal wells containing micro-fractures lack accuracy. Hence, the objective of this study is to build an efficient model to analyze well productivity, considering the effects of micro-fractures. A novel flow model for multi-fractured horizontal wells was established, considering the effect of micro-fractures on the fluid flow. Subsequently, we built a reservoir model based on the typical fracture and fluid properties of a tight oil block in the Daqing oil field, China. Good agreement between the prediction results and field data was obtained, indicating that the effect of micro-fractures on well productivity cannot be neglected. Further study reveals that micro-fractures essentially function as a joint connecting reservoir matrix and have a persistent impact on well productivity. Micro-fractures can promote well productivity; however, if the value of micro-fracture permeability increases, this promotional effect will slow down. Well productivity can be considerably improved as an increase in micro-fracture percentage. Finally, a series of sensitivity studies were conducted to identify the effects of critical parameters on well productivity. Results show that reservoir permeability significantly influences well productivity, followed by reservoir effective thickness, micro-fracture percentage, fracture number, hydraulic fracture half-length. Pressure sensitivity coefficient, threshold pressure gradient and micro-fracture permeability have the least effect on well productivity. This work provides a sophisticated and efficient tool to evaluate the productivity of multi-fractured horizontal wells in tight oil reservoirs with micro-fractures.

Reducing uncertainty in unconventional reservoir hydraulic fracture modeling: A case study in Saudi Arabia

Saudi Aramco is exploring and appraising liquid rich and dry gas unconventional reservoirs. Part of this effort has focused on understanding the effective fracture geometry and its role in optimal well spacing and reservoir drainage. A review of collected data and existing hypotheses indicated that there are multiple models for optimal production yet each calls for a dramatically different approach. Long term flow data is recommended in such cases but this is often complicated by the fact that decisions in a fast paced environment might rely on short production history.A field pilot in a carbonate-rich ultra-low permeability source rock in Saudi Arabia incorporated multiple hydraulic fracture monitoring techniques to validate outputs from a classical linear elastic fracture model. All employed monitoring techniques had their results assessed in conjunction with their strengths and weaknesses for more inclusive interpretations. From the reservoir flow regimes and the various hypotheses on effective fracture geometries, the extent to which non-uniqueness impacts determination of the most probable fracture geometry and matrix permeability was investigated. Long and short hydraulic fractures were used to match the short production history with reservoir simulation models under different sets of assumptions. The contradictions in the assumptions and difficulty in transferring fracture geometries, calibrated by the monitoring results, to production data modeling, were used to gauge the validity of associated effective fracture geometry hypotheses.From the pilot, microseismic monitoring indicated that more stimulation volumes yielded longer microseismic geometries. Offset well stimulation induced pressure interference in adjacent wells. Cross-well hydraulic communication illustrated by chemical and oil tracers corroborated the longer fractures mapped by microseismic events and also predicted by linear elastic fracture models. In addition, the sequential opening of the pilot pad wells induced subtle production-induced pressure interference in the early flow period. While the subtle production-induced pressure interference was initially thought to be the ground truth for adequate well spacing, it was shown that it was not unique due to the fact that ultra-low matrix permeability can prolong onset of fracture interference. The hydraulic fracture monitoring methods showed identical results for the estimated hydraulic fracture half-length which allowed the constraining of the parameter. Reservoir simulation was used to match the short production history with both short and long planar fractures even though the former had not been validated by most of the observed data. Consideration of all observed data, dimensionless fracture conductivity for stimulation design criteria and the reservoir simulation assumptions provided validation for long effective fractures.This study shows the contribution of a diverse surveillance data acquisition in reducing uncertainty in unconventional reservoir fracture modeling for realistic reservoir simulation and development solutions. In addition, insights derived from this work provided important clues for testing the validity of hypotheses in unconventional reservoir studies.

A New Criterion for a Toughness-Dominated Hydraulic Fracture Crossing a Natural Frictional Interface

Hydraulic fracturing is a powerful technology, especially in stimulating fluid production from reservoirs. However, the problem of the intersection between hydraulic fractures and natural fractures is inevitable in engineering practice due to naturally fractured formations. This paper presents a new criterion for a toughness-dominated hydraulic fracture crossing a natural frictional interface through coupling the fluid flow and elastic deformation of the hydraulic fracture prior to intersecting with the natural frictional interface. The critical condition for the hydraulic fracture crossing the natural frictional interface is that the total superimposed stress does not satisfy the failure condition of the Mohr–Coulomb criterion. Simultaneously, the new criterion considers nonorthogonal intersection angles and six independent parameters relating to fluid flow (hydraulic fracture half-length, approaching distance and injection rate), rock mechanic properties (rock fracture toughness and Young’s modulus) and in situ stress. The prediction outcomes show good agreement with laboratory experiments as well as sufficient advantages compared with the analytical criteria of Blanton, extended Renshaw-Pollard and Llanos. Parameter sensitivity analysis is conducted using the control variable method. The parametric analysis results reveal that the influence sphere of different parameters is limited to a certain extent by the variations in the intersection angle except for Young’s modulus and the injection rate, which show slight effects on the intersection behaviors.

Gas transport behaviors in shale nanopores based on multiple mechanisms and macroscale modeling

The combined action of multiple transport mechanisms and reservoir characteristics makes gas transport behaviors in nanoporous shale complicated. Accurate apparent gas permeability (AGP) characterization for gas transport in nanopores is crucially essential for macroscale modeling in shale gas reservoirs development. In this study, a new unified AGP model for gas transport in the organic and inorganic nanoporous shale (OM and IM) is presented, incorporating multiple mechanisms, such as real gas effect, viscous-slip flow, Knudsen diffusion, surface diffusion, stress dependence and especially the organic nanopores content. Besides, the effect of multilayer adsorption on gas transport is included. The model is validated by experimental and linearized Boltzmann results and compared with the published AGP models. After that, sensitivity analysis and the contribution of each mechanism to the total AGP are conducted. Moreover, a numerical model for the fractured well in shale based on the presented AGP model and discrete fracture model (DFM) is derived. The finite element method (FEM) is applied to solve the model and then influence factors of gas transport behaviors are discussed. The results show that different transport mechanisms exist in organic and inorganic nanopores respectively. The larger pore radius or pressure causes a smaller ratio of the AGP over the intrinsic permeability. Moreover, the contribution of surface diffusion to the total AGP is significantly influenced by the OM nanopores radius and surface diffusion coefficient. In addition, gas transport is governed by Knudsen diffusion in nanopores with a small radius and low pressure and is controlled by viscous flow under the large pore radius and high-pressure conditions. Then, the presented AGP model is introduced into the macroscale numerical model for a fractured well in shale. Larger hydraulic fracture half-length, OM nanopores content and matrix pore radius as well as smaller natural fracture spacing cause higher gas production. The study provides a new unified AGP model considering gas transport behaviors in nanopores and applies the AGP model to macroscale modeling.

A fractal production prediction model for shale gas reservoirs

A production forecasting model for shale gas reservoirs is proposed based on the continuum medium theory (organic/inorganic matrix) and discrete fracture model (fracture system). The fractal property of the pore size distribution of shale matrix is considered. The stability and accuracy of the model are successfully validated with the field data. Variations of different flow mechanisms during the exploitation of shale gas are investigated. The sensitivities of gas production to the pore size distribution of shale matrix, natural fracture parameters and hydraulic fracture parameters are analyzed. Our results show that: (1) The contribution of the convective flow and surface diffusion to total gas flow increases with the depletion of shale gas, while that of the bulk diffusion and Knudsen diffusion decreases gradually. (2) Among the fractal pore-size parameters, the maximum inorganic pore diameter has the most significant impact on the cumulative gas production of up to 13.9%. (3) After the natural fracture number increases to a certain extent, gas production increases slowly even if more natural fractures exist in the reservoir. The complex fracture network is beneficial to increase shale gas production. (4) The cumulative gas production rises as the increase of the hydraulic fracture half-length, flow conductivity, spacing and number. The rapid production rate in the early production stage may result in a fast reservoir energy depletion, which has a negative effect on production.

Application of fast analytical approach and AI optimization techniques to hydraulic fracture stage placement in shale gas reservoirs

In the last decades, natural gas from unconventional reservoirs has become a major portion of total gas supply due to advances in horizontal well drilling and multi-stage hydraulic fracturing as well as reduction of operational costs and capital expenditures. However, hydraulic fracturing technique is a still costly and resource intensive production strategy that requires optimal planning to conform to the best safety practices and to obtain the highest returns on investments. Thus, the proposed fast and reliable hydraulic fracture (HF) placement optimization technique based on physics and analytical equations is the key tool to balance between gas production costs and anticipated revenues.In this study, we develop an analytical model in which the modified Wattenbarger slab model with the pseudo-pressure approach are integrated into the Net Present Value (NPV) as the objective function. We consider four decision variables including number of HF stages, HF spacing, HF half-length, and wellbore spacing and use three stochastic gradient-free optimization methods (i.e., genetic algorithm (GA), differential evolution (DE), and particle swarm optimization (PSO)) to optimize the objective function on a synthetic shale gas reservoir model with the Barnett Shale properties. To verify the accuracy of the obtained optimal solutions, we conduct four trials for each stochastic optimization method with 100 generations and the population size of 20. The results show that the best overall value of the NPV found by PSO are 1.7% and 7.6% higher than those obtained by DE and GA, respectively. Moreover, PSO has the fastest convergence rate (in 50 generations), saves at least 10% of the computational time in comparison to those required by other methods, and results in the same optimal solution in all trials. Finally, considering bilinear flow at the early stages of the production period, nonlinear flow at the late production time, and gravitational effects in the analytical model are still open areas for future research in this field.

How much stimulated reservoir volume and induced matrix permeability could enhance unconventional reservoir performance

This paper investigates the impacts of stimulated reservoir volume (SRV) on reservoir performance for unconventional hydraulically fractured formations. It focuses also on the effects of different petrophysical properties of SRV as well as different volume and petrophysical properties of unstimulated part of porous media (USRV). The influences of hydraulic fracture conductivity, fracture assymmetricity, and non-Darcy flow permeability in reservoir pressure profile have been substantially studied in this paper. Stimulated reservoir volume represents the volume of porous media where complex network structures formed from naturally induced fractures, multiple hydraulic fractures, and original matrix. SRV is characterized by an induced or a stimulated matrix permeability which is typically greater than the original matrix permeability. The formations of interest, in this study, are considered having either stimulated reservoir volume only or both stimulated and un-stimulated reservoir volumes and depleted by multiple hydraulic fractures controlled by non-Darcy flow.The impacts of SRV and USRV on pressure distributions, flow regimes, and productivity indices have been studied using multi-linear flow regimes approach. A new analytical model has been proposed in this paper for pressure behavior of a horizontal well intersected by multiple hydraulic fractures assuming symmetrical and asymmetrical stimulated reservoir volumes. This model was developed using multi-linear flow regimes approach with an adjustment for variable SRVs and USRVs. The volume of stimulated part in the reservoir is determined by hydraulic fracture half length, number of fractures and spacing between them, and fracture height. The impact of induced or stimulated matrix permeability in the stimulated reservoir volume and fracture conductivity as well as non-Darcy flow impact on pressure behaviors have also been investigated. Several analytical models for flow regimes, expected to develop during the entire production life of reservoir, were also proposed in this study. A set of type-curves was designed for pseudo-pressure normalized rate and pseudo-pressure normalized cumulative rate with production time.The outcomes of this study can be summarized as: 1) Generating an analytical model that describes pressure behavior in unconventional reservoirs and considers variable SRVs and USRVs. This model includes stimulated matrix permeability, non-Darcy flow impact, and hydraulic fracture conductivity. 2) Understanding the impact of asymmetrical stimulated reservoir volumes on reservoir performance. 3) Developing analytical models for different linear flow regimes that could develop during the entire life of reservoir. 4) Comparing the productivity index for different stimulated and un-stimulated reservoir volumes assuming both symmetrical and asymmetrical reservoir volume. The most interesting points in this study are: 1) Productivity index drops significantly for the case of asymmetrical SRVs compared to symmetrical SRVs. 2) The SRV enhances productivity index more than USRV, however, at early production time, there is no impact for both of them on productivity index. 3) The impact of assymmetricity is seen at all production time. 4) Flow regime types are not changed with respect to the assymmetricity.

Effect of Shale Reservoir Property and Condition of Hydraulic Fracture on Decline Curve Analysis Factor

As technology advances, there has been increasing interest in developing shale gas. Analysis and estimation of shale gas production behavior are necessary for shale gas development. In this paper, simulation of shale gas production was performed depending on reservoir properties (porosity and permeability of matrix and natural fracture) and condition of hydraulic fracture (half-length and spacing). The effect of reservoir properties and the condition of hydraulic fracture on production behavior of shale gas were examined. Decline curve analysis (DCA) factors, which represent production behavior of shale gas, were derived by matching process between DCA and simulation result. The variation of shale gas production behavior was understood by analyzing the variation of DCA factors. The qualitative relationship between influential parameters (reservoir properties and the condition of hydraulic fracture) and production behavior of shale gas was identified and the degree of influence by each parameter was analyzed.

Unconventional multi-fractured analytical solution using dual porosity model

Five-region linear flow system proved to be a useful model to reproduce the flow behavior for multi-fractured horizontal wells in shale reservoirs. In earlier developments, the model was assumed single-porosity throughout all five regions. However, assumption of single porosity system for stimulated region may promote errors in pressure transient analysis. So by adopting the existing mathematical models for naturally fractured reservoirs (dual-porosity system), one can apply the dual-porosity nature of flow in the stimulated reservoir volume (SRV). In this study the analytical solution for single-porosity model is reproduced and compared with numerical solution. Then the five-region model of previous studies is modified by implementing the dual porosity behavior in Laplace domain and compared to single-porosity solution using the same reservoir properties. Furthermore, a series of type-curves is constructed in this study using dimensionless properties, such as matrix-fracture capacity ratio and storativity ratio, hydraulic fracture conductivity, and hydraulic fracture half-length. Theses curves could provide valuable information to characterize the multi-fractured complex systems.

Evaluation of CO2 injection in shale gas reservoirs with multi-component transport and geomechanical effects

Although research on CO2 injection in shale gas reservoirs has been focused for enhanced gas recovery (EGR) and CO2 storage, previous studies have not examined both multi-component transport and geomechanical effects. Therefore, this study presents new shale gas models for CO2 injection considering multi-component adsorption, dissolution, molecular diffusion, and stress-dependent compaction. Based on these mechanisms and data for Barnett shale field, a simulation model was constructed for CO2 flooding and huff and puff. The proposed model was used to examine the effects of CO2 injection to EGR and CO2 storage and various mechanisms. The results presented that CO2 flooding and huff and puff improve CH4 production by 24% and 6% respectively compared with no injection scenario. At the end of simulated time, the injected CO2 is stored as free, adsorbed, and dissolved states in proportions of 42%, 55%, and 3% respectively. To confirm these results, Marcellus and New Albany shale models, which have different reservoir properties, are generated and compared with Barnett shale model. However, in Marcellus and New Albany shale models, effects of CO2 injection are lower than that of Barnett shale model. Therefore, to investigate factors affecting to the efficiency of CO2 injection in shale gas reservoirs, extensive simulations were performed. Results of the simulation analyses show that natural fracture permeability, hydraulic fracture half-length, well spacing, and Langmuir constants are significant factors for EGR and CO2 storage. For the real applications, these parameters should be mainly considered. The investigations performed in this study present better understanding of CO2 injection processes to EGR and CO2 storage and they are important for optimizing the designs of CO2 injection in field applications.

Qualitative modeling of multi-stage fractured horizontal well productivity in shale gas reservoir

As an important unconventional gas resource, shale gas has become an important part of gas production in recent years with the advantage of horizontal well drilling and large-scale multi-stage hydraulic fracturing completion technologies. The shale gas reservoir numerical simulation advances were reviewed and a multi-stage fractured horizontal well numerical simulation was performed to qualitatively modeling the well productivity in over-pressured shale gas reservoir based on actual shale properties and well completion parameters. A single horizontal well model was established on the basis of dual-porosity model and logarithmically spaced grid refinement. A comprehensive comparison and analysis of the initial average gas production, daily gas production, cumulative gas production, adsorbed gas and free gas cumulative production were provided to investigate the influence of matrix permeability, SRV permeability, hydraulic fracture conductivity and half length, SRV size, bottomhole pressure on the well performance. The research shows that for the high matrix permeability (Km > 10−7 mD) and low SRV permeability (KSRV < 0.01 mD), the SRV permeability has a significant impact on the initial average gas production. For the high matrix permeability (Km > 10−7 mD) and medium SRV permeability (0.01 mD < KSRV < 0.5 mD), the initial average gas production is controlled by both the matrix and SRV permeability. For the high matrix permeability (Km > 10−7 mD) and high SRV permeability (KSRV > 0.5 mD), the initial average gas production is mainly controlled by the matrix permeability. When the matrix permeability is lower than 10−9 mD, the cumulative gas production is too low to be of economic interest. For the matrix permeability (10−9 mD < Km < 10−5 mD), the matrix permeability and SRV permeability are all important factors that influence the cumulative gas production. For the matrix permeability (Km > 10−5 mD), the matrix permeability has much more impact on cumulative gas production than that of SRV permeability. The daily gas production and cumulative gas production are independent of hydraulic fracture conductivity and half length. The initial gas production of multi-stage fractured horizontal well is also independent of SRV sizes. The SRV size mainly controls the gas production decline characteristic. With the increase of the SRV size, the daily gas production declines slowly. The SRV size determines the cumulative gas production directly. With the increase of the SRV size, the cumulative gas production increases linearly. The bottomhole pressure has a significant impact on cumulative gas production. With the decrease of the bottomhole pressure, the cumulative gas production of 20 years increases linearly.

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.