scholarly journals Nonlinear Seepage Model of Gas Transport in Multiscale Shale Gas Reservoirs and Productivity Analysis of Fractured Well

2015 ◽  
Vol 2015 ◽  
pp. 1-10 ◽  
Author(s):  
Ting Huang ◽  
Xiao Guo ◽  
Kun Wang
Keyword(s):  
Gas Flow ◽  
Slip Flow ◽  
Gas Production ◽  
Productivity Analysis ◽  
Transition Flow ◽  
Gas Reservoirs ◽  
Slippage Effect ◽  
Wellbore Pressure ◽  
Fractured Well ◽  
And Diffusion

Shale is abundant in nanoscale pores, so gas flow in shales cannot be simply represented by Darcy formula anymore. It is crucial to figure out the influence of gas flow in nano/micro pores on actual productivity, which can provide basic theories for optimizing parameters and improving the gas production from engineering perspective. This paper considers the effects of slippage and diffusion in nanoscale based on Beskok-Karniadakis (BK) equation, which can be applicable for different flow regimes including continuum flow, slip flow, transition flow, and free-molecule flow. A new non-Darcy equation was developed based on the analysis of effects of high order terms of BK equation on permeability correction factor. By using the conformal transformation principle and pressure coupling method, we established the productivity formula of fractured well (infinite and limited conductivity) satisfying mass variable seepage flowing in fractures. The simulation results have been compared with field data and influencing parameters are analyzed thoroughly. It is concluded that slippage effect affects gas production of fractured well when wellbore pressure is less than 15 MPa, and the effects of slippage and diffusion have greater influence on gas production of fractured well for reservoir with smaller permeability, especially when permeability is at nano-Darcy scale.

Laboratory measurement and interpretation of nonlinear gas flow in shale

2015 ◽  
Vol 26 (06) ◽  
pp. 1550063 ◽  
Author(s):  
Yili Kang ◽  
Mingjun Chen ◽  
Xiangchen Li ◽  
Lijun You ◽  
Bin Yang
Keyword(s):  
Pore Pressure ◽  
Gas Flow ◽  
Gas Adsorption ◽  
Slip Flow ◽  
Transition Flow ◽  
Confining Stress ◽  
Slippage Effect ◽  
Longmaxi Shale ◽  
Close Relationship ◽  
Flow Mechanisms

Gas flow mechanisms in shale are urgent to clarify due to the complicated pore structure and low permeability. Core flow experiments were conducted under reservoir net confining stress with samples from the Longmaxi Shale to investigate the characteristics of nonlinear gas flow. Meanwhile, microstructure analyses and gas adsorption experiments are implemented. Experimental results indicate that non-Darcy flow in shale is remarkable and it has a close relationship with pore pressure. It is found that type of gas has a significant influence on permeability measurement and methane is chosen in this work to study the shale gas flow. Gas slippage effect and minimum threshold pressure gradient weaken with the increasing backpressure. It is demonstrated that gas flow regime would be either slip flow or transition flow with certain pore pressure and permeability. Experimental data computations and microstructure analyses confirm that hydraulic radius of flow tubes in shale are mostly less than 100 nm, indicating that there is no micron scale pore or throat which mainly contributes to flow. The results are significant for the study of gas flow in shale, and are beneficial for laboratory investigation of shale permeability.

scholarly journals Simulation of Gas Transport in Tight/Shale Gas Reservoirs by a Multicomponent Model Based on PEBI Grid

2015 ◽  
Vol 2015 ◽  
pp. 1-9 ◽  
Author(s):  
Longjun Zhang ◽  
Daolun Li ◽  
Lei Wang ◽  
Detang Lu
Keyword(s):  
Shale Gas ◽  
Slip Flow ◽  
Gas Production ◽  
Darcy Flow ◽  
Molecular Flow ◽  
Flow Transition ◽  
Free Molecular Flow ◽  
Transition Flow ◽  
Gas Reservoirs ◽  
Fracture Length

The ultra-low permeability and nanosize pores of tight/shale gas reservoir would lead to non-Darcy flow including slip flow, transition flow, and free molecular flow, which cannot be described by traditional Darcy’s law. The organic content often adsorbs some gas content, while the adsorbed amount for different gas species is different. Based on these facts, we develop a new compositional model based on unstructured PEBI (perpendicular bisection) grid, which is able to characterize non-Darcy flow including slip flow, transition flow, and free molecular flow and the multicomponent adsorption in tight/shale gas reservoirs. With the proposed model, we study the effect of non-Darcy flow, length of the hydraulic fracture, and initial gas composition on gas production. The results show both non-Darcy flow and fracture length have significant influence on gas production. Ignoring non-Darcy flow would underestimate 67% cumulative gas production in lower permeable gas reservoirs. Gas production increases with fracture length. In lower permeable reservoirs, gas production increases almost linearly with the hydraulic fracture length. However, in higher permeable reservoirs, the increment of the former gradually decreases with the increase in the latter. The results also show that the presence of CO2in the formation would lower down gas production.

scholarly journals Unconventional Gas Production from Hydraulically Fractured Well-An Application of Direct Search Based Optimization Algorithm

2019 ◽  
Vol 8 (2S11) ◽  
pp. 2726-2737
Keyword(s):  
Objective Function ◽  
Fracture Propagation ◽  
Gas Production ◽  
Production Model ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Unconventional Gas ◽  
Fracture Geometry ◽  
Propagation Behavior ◽  
Fractured Well

Unconventional gas reservoirs are now the targets for meeting the demand for gas. These reservoirs are at the depth of more than 10,000 ft (even over 15000 depth as well) and are difficult to be exploited by conventional methods. For the last decades hydraulic fracturing has become the tool to develop these resources. Mathematical models (2D and pseudo-3D) have been developed for fracture geometry, which should be realistically created at the depth by surface controllable treatment parameters. If the reservoir rock is sandstone, then proppant fracturing is suitable and if the rock is carbonates, then acid fracturing is applicable. In both cases, proper design of controllable treatment parameters within constraints is essential. This needs proper optimization model which gives real controllable parametric vales. The model needs the most important analyses from geomechanical study and linear elastic fracture mechanics of rock containing unconventional gas so that fracture geometry makes maximum contact with the reservoirs for maximum recovery. Currently available software may lack proper optimization scheme containing geomechanical stress model, fracture geometry, natural fracture interactions, real field constraints and proper reservoir engineering model of unconventional gas resources, that is, production model from hydraulically fractured well (vertical and horizontal). An optimization algorithm has been developed to integrate all the modules, as mentioned above, controllable parameters, field constraints and production model with an objective function of maximum production (with or without minimization of treatment cost). Optimization is basically developed based on Direct Search Genetic and Polytope algorithm, which can handle dual objective function, non-differentiable equations, discontinuity and non-linearity. A dual objective function will meet operator’s economic requirements and investigate conflict between two objectives. The integrated model can be applied to a vertical or horizontal well in tight gas or ultra-tight shale gas deeper than over 10,000 ft. A simulation (with industrial simulators) was conducted to investigate and analyse fracture propagation behavior, under varying parameters with respect to the fracture design process, for tight gas reservoirs. Results indicate that hydraulic fracture propagation behavior is not uninhibited in deep reservoirs as some may believe that minor variations of variables such as in-situ stress, fluid properties etc. are often detrimental to fracture propagation in some conditions. Application of this model to a hypothetical tight and ultra-tight unconventional gas formations indicates a significant gas production at lower treatment cost; whereas the resources do not flow without any stimulation (hydraulic fracturing).

scholarly journals Petrophysical Characterizations of Shale Gas Reservoirs of the Ranikot Formation in the Lower Indus Basin, Pakistan

2021 ◽  
Vol 3 (2) ◽  
pp. 103-107
Author(s):  
Kazunori Abe ◽  
Nouman Zobby ◽  
Hikari Fujii
Keyword(s):  
Pore Structure ◽  
Pore Size ◽  
Density Functional ◽  
Gas Flow ◽  
Slip Flow ◽  
Indus Basin ◽  
Size Distributions ◽  
Gas Reservoirs ◽  
Lower Indus Basin ◽  
Pore Size Distributions

The complex pore structure with nano-pores of shale gas reservoirs has an impact on the hydrocarbon storage and transport systems. We examined the pore structure of the shales of the Ranikot Formation in the Lower Indus Basin, Pakistan to investigate the full scaled pore size distributions by using a combination of techniques, mercury injection capillary pressure analysis and low pressure gas adsorption methods using N2 and CO2. Isotherm curves obtained N2 and CO2 adsorptions were interpreted using density functional theory analysis for describing the nano-scaled pore size distributions. The pore geometry of the shales was estimated to be slit-type from the isotherm hysteresis loop shape. The pore size distributions determined the density functional theory showed the dominant pore size of below around 10 nm. The Micro-scale effects such as slippage and adsorption/desorption also significantly influence the gas flow in nano-pore structure. The gas flow regimes in shales are classified into four types Darcy flow, slip flow, transition flow, Knudsen flow based on the value of the Knudsen number. Applying the specific reservoir conditions in Ranikot shale and pore size distribution to the Knudsen number, the gas flow regimes of the Ranikot shales were estimated mostly within the transition and slip flow.

scholarly journals History Matching and Forecast of Shale Gas Production Considering Hydraulic Fracture Closure

Energies ◽  
2019 ◽  
Vol 12 (9) ◽  
pp. 1634 ◽  
Author(s):  
Juhyun Kim ◽  
Youngjin Seo ◽  
Jihoon Wang ◽  
Youngsoo Lee
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
History Matching ◽  
Gas Flow ◽  
Fluid Pressure ◽  
Gas Production ◽  
Hydraulic Fractures ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Fracture Closure

Most shale gas reservoirs have extremely low permeability. Predicting their fluid transport characteristics is extremely difficult due to complex flow mechanisms between hydraulic fractures and the adjacent rock matrix. Recently, studies adopting the dynamic modeling approach have been proposed to investigate the shape of the flow regime between induced and natural fractures. In this study, a production history matching was performed on a shale gas reservoir in Canada’s Horn River basin. Hypocenters and densities of the microseismic signals were used to identify the hydraulic fracture distributions and the stimulated reservoir volume. In addition, the fracture width decreased because of fluid pressure reduction during production, which was integrated with the dynamic permeability change of the hydraulic fractures. We also incorporated the geometric change of hydraulic fractures to the 3D reservoir simulation model and established a new shale gas modeling procedure. Results demonstrate that the accuracy of the predictions for shale gas flow improved. We believe that this technique will enrich the community’s understanding of fluid flows in shale gas reservoirs.

scholarly journals Production Data Analysis and Practical Applications in the Sulige Tight Gas Reservoir, Ordos Basin, China

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-10
Author(s):  
Minhua Cheng ◽  
Wen Xue ◽  
Meng Zhao ◽  
Guoting Wang ◽  
Bo Ning ◽  
...  
Keyword(s):  
Data Analysis ◽  
Ordos Basin ◽  
Gas Production ◽  
Production Data ◽  
Gas Reservoirs ◽  
Tight Sandstone ◽  
Gas Reservoir ◽  
Well Pattern ◽  
Tight Gas Reservoir ◽  
Wellbore Pressure

Successful exploitation of tight sandstone gas is one of the important means to ensure the “increasing reserves and production” of the oil and gas initiative and also one of the important ways to ensure national energy security. To further improve the accuracy of historical matching of field data such as gas production and bottom-hole pressure during the production process of this type of gas reservoir, in this study, a new expression of wellbore pressure for the uniform flow of vertical fractured wells in Laplace space based on the point sink function model of vertical fractures in tight sandstone gas reservoirs is constructed. This innovation is based on a typical production data analysis plot of the Blasingame type that uses the numerical inversion decoupling mathematical equation. After analyzing the pressure and pressure derivative characteristics of each flow stage in the typical curves, a new technique of type-curve matching was proposed. In order to verify the correctness of the model and the application value of the field, based on the previous production data of Sulige Gas Field in China, a new set of production data diagnostic chart of tight sandstone gas reservoir was formed. A case analysis showed that the application of the production data analysis method and data diagnosis plot in the field accurately evaluated the development effect of the tight sandstone gas reservoirs, clarified the scale of effective sand bodies, and provided technical support for optimizing and improving the well pattern and realizing the efficient development of gas fields.

A Generalized Framework Model for the Simulation of Gas Production in Unconventional Gas Reservoirs

SPE Journal ◽  
2014 ◽  
Vol 19 (05) ◽  
pp. 845-857 ◽  
Author(s):  
Yu-Shu Wu ◽  
Jianfang Li ◽  
Didier-Yu Ding ◽  
Cong Wang ◽  
Yuan Di
Keyword(s):  
Shale Gas ◽  
Gas Flow ◽  
Gas Production ◽  
Unconventional Reservoirs ◽  
Hydraulic Fractures ◽  
Gas Reservoirs ◽  
Unconventional Gas ◽  
Shale Gas Reservoirs ◽  
Framework Model ◽  
Unconventional Gas Reservoirs

Summary Unconventional gas resources from tight-sand and shale gas reservoirs have received great attention in the past decade around the world because of their large reserves and technical advances in developing these resources. As a result of improved horizontal-drilling and hydraulic-fracturing technologies, progress is being made toward commercial gas production from such reservoirs, as demonstrated in the US. However, understandings and technologies needed for the effective development of unconventional reservoirs are far behind the industry needs (e.g., gas-recovery rates from those unconventional resources remain very low). There are some efforts in the literature on how to model gas flow in shale gas reservoirs by use of various approaches—from modified commercial simulators to simplified analytical solutions—leading to limited success. Compared with conventional reservoirs, gas flow in ultralow-permeability unconventional reservoirs is subject to more nonlinear, coupled processes, including nonlinear adsorption/desorption, non-Darcy flow (at both high flow rate and low flow rate), strong rock/fluid interaction, and rock deformation within nanopores or microfractures, coexisting with complex flow geometry and multiscaled heterogeneity. Therefore, quantifying flow in unconventional gas reservoirs has been a significant challenge, and the traditional representative-elementary-volume- (REV) based Darcy's law, for example, may not be generally applicable. In this paper, we discuss a generalized mathematical framework model and numerical approach for unconventional-gas-reservoir simulation. We present a unified framework model able to incorporate known mechanisms and processes for two-phase gas flow and transport in shale gas or tight gas formations. The model and numerical scheme are based on generalized flow models with unstructured grids. We discuss the numerical implementation of the mathematical model and show results of our model-verification effort. Specifically, we discuss a multidomain, multicontinuum concept for handling multiscaled heterogeneity and fractures [i.e., the use of hybrid modeling approaches to describe different types and scales of fractures or heterogeneous pores—from the explicit modeling of hydraulic fractures and the fracture network in stimulated reservoir volume (SRV) to distributed natural fractures, microfractures, and tight matrix]. We demonstrate model application to quantify hydraulic fractures and transient flow behavior in shale gas reservoirs.

Production-Data Analysis of Gas Reservoirs With Apparent-Permeability and Sorbed-Phase Effects: A Density-Based Approach

SPE Journal ◽  
2015 ◽  
Vol 20 (01) ◽  
pp. 99-111 ◽  
Author(s):  
Pichit Vardcharragosad ◽  
Luis F. Ayala H.
Keyword(s):  
Gas Flow ◽  
Liquid Solution ◽  
Gas Production ◽  
Production Performance ◽  
Production Data ◽  
Gas Reservoirs ◽  
Apparent Permeability ◽  
Gas Slippage ◽  
Natural Gas Reservoirs ◽  
Sorbed Phase

Summary Accounting for depletion-dependent permeability and sorbed-phase effects is an important step toward achieving reliable analysis of production performance in unconventional gas systems. This study demonstrates how to account for pressure-dependent apparent-permeability (e.g., gas-slippage) and desorption effects in gas-production analysis of boundary-dominated data with a density-based approach. In this work, apparent-permeability and desorption models are incorporated into the original density-based approach by modifying the definitions of depletion-driven variables that are the basis of the density-based type of analysis. The proposed modification of the original approach successfully enables associated analysis techniques to be applicable to natural-gas reservoirs with gas slippage and adsorbed gas. Results indicate that by modifying the definitions of the depletion-driven variables, the density approach can effectively and successfully capture the effects from gas slippage and desorption. Through a number of case studies, we show that gas-flow rate can be successfully predicted by rescaling liquid solution with the modified density-based variables. As an illustration, we show that resource calculations able to fully take into account these effects are possible when long-term production data are available. This work details the methodology required to do so, and illustrates its application to production-data prediction analysis for unconventional assets.

scholarly journals A non-empirical model for gas transfer through circular nanopores in unconventional gas reservoirs

2021 ◽  
Vol 11 (5) ◽  
pp. 2217-2232
Author(s):  
Jiangtao Li ◽  
Jianguang Wei ◽  
Liang Ji ◽  
Anlun Wang ◽  
Gen Rong ◽  
...  
Keyword(s):  
Gas Flow ◽  
Gas Transport ◽  
Transport Model ◽  
Knudsen Diffusion ◽  
Slip Flow ◽  
Gas Reservoirs ◽  
Permeability Model ◽  
Proposed Model ◽  
Unconventional Gas Reservoirs ◽  
Empirical Coefficients

AbstractIt is difficult to predict the flow performance in the nanopore networks since traditional assumptions of Navier–Stokes equation break down. At present, lots of attempts have been employed to address the proposition. In this work, the advantages and disadvantages of previous analytical models are seriously analyzed. The first type is modifying a mature equation which is proposed for a specified flow regime and adapted to wider application scope. Thus, the first-type models inevitably require empirical coefficients. The second type is weight superposition based on two different flow mechanisms, which is considered as the reasonable establishment method for universal non-empirical gas-transport model. Subsequently, in terms of slip flow and Knudsen diffusion, the novel gas-transport model is established in this work. Notably, the weight factors of slip flow and Knudsen diffusion are determined through Wu’s model and Knudsen’s model respectively, with the capacity to capture key transport mechanism through nanopores. Capturing gas flow physics at nanoscale allows the proposed model free of any empirical coefficients, which is also the main distinction between our work and previous research. Reliability of proposed model is verified by published molecular simulation results as well. Furthermore, a novel permeability model for coal/shale matrix is developed based on the non-empirical gas-transport model. Results show that (a) nanoconfined gas-transport capacity will be strengthened with the decline of pressure and the decrease in the pressure is supportive for the increasing amplitude; (b) the greater pore size the nanopores is, the stronger the transport capacity the nanotube is; (c) after field application with an actual well in Fuling shale gas field, China, it is demonstrated that numerical simulation coupled with the proposed permeability model can achieve better historical match with the actual production performance. The investigation will contribute to the understanding of nanoconfined gas flow behavior and lay the theoretical foundation for next-generation numerical simulation of unconventional gas reservoirs.

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