Analysis of Production Data From Hydraulically Fractured Horizontal Wells in Shale Reservoirs

2010 ◽  
Vol 13 (03) ◽  
pp. 559-568 ◽  
Author(s):  
F.. Medeiros ◽  
B.. Kurtoglu ◽  
E.. Ozkan ◽  
H.. Kazemi
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
Horizontal Wells ◽  
Productivity Index ◽  
Production Data ◽  
Shale Oil ◽  
Reservoir Heterogeneity ◽  
Key Features ◽  
Shale Reservoirs ◽  
Fractured Horizontal Wells

Summary This paper discusses the analysis of production data from hydraulically fractured horizontal wells in shale reservoirs. The stimulated volume around the well is simulated by a naturally fractured region. A semianalytical model incorporating the key features of reservoir heterogeneity and the details of hydraulic fracture and wellbore flow is used to present production-decline characteristics in terms of transient-productivity index. Production-decline analysis of fractured horizontal wells in shale-oil and shale-gas formations by transient-productivity index is explained and demonstrated by field applications.

Comparison of Fractured-Horizontal-Well Performance in Tight Sand and Shale Reservoirs

2011 ◽  
Vol 14 (02) ◽  
pp. 248-259 ◽  
Author(s):  
E.. Ozkan ◽  
M Brown ◽  
R.. Raghavan ◽  
H.. Kazemi
Keyword(s):  
Hydraulic Fracture ◽  
Horizontal Well ◽  
Flow Model ◽  
Horizontal Wells ◽  
Natural Fracture ◽  
Well Performance ◽  
Fracture Conductivity ◽  
Fractured Horizontal Well ◽  
Shale Reservoirs ◽  
Fractured Horizontal Wells

Summary This paper presents a discussion of fractured-horizontal-well performance in millidarcy permeability (conventional) and micro- to nanodarcy permeability (unconventional) reservoirs. It provides interpretations of the reasons to fracture horizontal wells in both types of formations. The objective of the paper is to highlight the special productivity features of unconventional shale reservoirs. By using a trilinear-flow model, it is shown that the drainage volume of a multiple-fractured horizontal well in a shale reservoir is limited to the inner reservoir between the fractures. Unlike conventional reservoirs, high reservoir permeability and high hydraulic-fracture conductivity may not warrant favorable productivity in shale reservoirs. An efficient way to improve the productivity of ultratight shale formations is to increase the density of natural fractures. High natural-fracture conductivities may not necessarily contribute to productivity either. Decreasing hydraulic-fracture spacing increases the productivity of the well, but the incremental production gain for each additional hydraulic fracture decreases. The trilinear-flow model presented in this work and the information derived from it should help the design and performance prediction of multiple-fractured horizontal wells in shale reservoirs.

A practical method for production data analysis from multistage fractured horizontal wells in shale gas reservoirs

Fuel ◽  
2016 ◽  
Vol 186 ◽  
pp. 821-829 ◽  
Author(s):  
Yonghui Wu ◽  
Linsong Cheng ◽  
Shijun Huang ◽  
Pin Jia ◽  
Jin Zhang ◽  
...  
Keyword(s):  
Data Analysis ◽  
Shale Gas ◽  
Horizontal Wells ◽  
Practical Method ◽  
Production Data ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Fractured Horizontal Wells

Integrated Investigation of Dynamic Drainage Volume and Inflow Performance Relationship (Transient IPR) to Optimize Multistage Fractured Horizontal Wells in Tight/Shale Formations

2016 ◽  
Vol 138 (5) ◽  
Author(s):  
Bin Yuan ◽  
Rouzbeh Ghanbarnezhad Moghanloo ◽  
Emad Shariff
Keyword(s):  
Transient Flow ◽  
Horizontal Wells ◽  
Integrated Approach ◽  
Shale Oil ◽  
Horizontal Section ◽  
Fracture Spacing ◽  
Drainage Volume ◽  
Shale Reservoirs ◽  
Fractured Horizontal Wells ◽  
Inflow Performance

This study presents an integrated approach to evaluate the efficiency of fracturing stimulation and predict well production performance. As the pressure disturbance propagates throughout the reservoir during long-time transient flow regimes, it will shape an expanding drainage volume. A macroscopic “compressible tank model (CTM)” using weak (integral) form of mass balance equation is derived to relate dynamic drainage volume (DDV) and average reservoir pressure to production history in extremely shale reservoirs. Fluids and rock compressibility, desorption parameters (for shale or coal gas), and production rates control the speed at which the boundaries advance. After the changes of average reservoir pressure within the expanding drainage volume are obtained, a new empirical inflow performance relationship (transient IPR) correlation is proposed to describe well performance during long transient flow periods in shale reservoirs. This new empirical correlation shows better match performance with field data than that of conventional Vogel-type IPR curves. The integrated approach of both CTM model and transient IPR correlation is used to determine and predict the optimal fracturing spacing and the size of horizontal section for few wells from one of shale oil plays in U.S. The results suggest the existence of optimal fracture spacing and horizontal well length for multistage fractured horizontal wells in shale oil reservoirs. In practice, this paper not only provides an insight in understanding the long transient flow production characteristics of shale reservoirs using concept of expanding drainage volume. Neither methods require comprehensive inputs for the strong form (differential) nor any prior knowledge about the sophisticated shale reservoir features (shape, size, etc.), the ultimate drainage volume, the ultimate recovery, optimal fracture spacing, and the length of horizontal section for each well can also be easily obtained by this new integrated analytical method.

History Matching and Rate Forecasting in Unconventional Oil Reservoirs With an Approximate Analytical Solution to the Double-Porosity Model

2015 ◽  
Vol 19 (01) ◽  
pp. 070-082 ◽  
Author(s):  
B. A. Ogunyomi ◽  
T. W. Patzek ◽  
L. W. Lake ◽  
C. S. Kabir
Keyword(s):  
Analytical Solution ◽  
History Matching ◽  
Horizontal Wells ◽  
Double Porosity ◽  
Unconventional Reservoirs ◽  
Production Data ◽  
Time Space ◽  
Double Porosity Model ◽  
Fractured Horizontal Wells ◽  
Porosity Model

Summary Production data from most fractured horizontal wells in gas and liquid-rich unconventional reservoirs plot as straight lines with a one-half slope on a log-log plot of rate vs. time. This production signature (half-slope) is identical to that expected from a 1D linear flow from reservoir matrix to the fracture face, when production occurs at constant bottomhole pressure. In addition, microseismic data obtained around these fractured wells suggest that an area of enhanced permeability is developed around the horizontal well, and outside this region is an undisturbed part of the reservoir with low permeability. On the basis of these observations, geoscientists have, in general, adopted the conceptual double-porosity model in modeling production from fractured horizontal wells in unconventional reservoirs. The analytical solution to this mathematical model exists in Laplace space, but it cannot be inverted back to real-time space without use of a numerical inversion algorithm. We present a new approximate analytical solution to the double-porosity model in real-time space and its use in modeling and forecasting production from unconventional oil reservoirs. The first step in developing the approximate solution was to convert the systems of partial-differential equations (PDEs) for the double-porosity model into a system of ordinary-differential equations (ODEs). After which, we developed a function that gives the relationship between the average pressures in the high- and the low-permeability regions. With this relationship, the system of ODEs was solved and used to obtain a rate/time function that one can use to predict oil production from unconventional reservoirs. The approximate solution was validated with numerical reservoir simulation. We then performed a sensitivity analysis on the model parameters to understand how the model behaves. After the model was validated and tested, we applied it to field-production data by partially history matching and forecasting the expected ultimate recovery (EUR). The rate/time function fits production data and also yields realistic estimates of ultimate oil recovery. We also investigated the existence of any correlation between the model-derived parameters and available reservoir and well-completion parameters.

scholarly journals Water-Gas Two-Phase Flow Behavior of Multi-Fractured Horizontal Wells in Shale Gas Reservoirs

Processes ◽  
2019 ◽  
Vol 7 (10) ◽  
pp. 664 ◽  
Author(s):  
Lei Li ◽  
Guanglong Sheng ◽  
Yuliang Su
Keyword(s):  
Organic Matter ◽  
Shale Gas ◽  
Flow Behavior ◽  
Horizontal Wells ◽  
Gas Production ◽  
Phase Flow ◽  
Gas Reservoirs ◽  
Two Phase ◽  
Fractured Horizontal Wells ◽  
Water Gas

Hydraulic fracturing is a necessary method to develop shale gas reservoirs effectively and economically. However, the flow behavior in multi-porosity fractured reservoirs is difficult to characterize by conventional methods. In this paper, combined with apparent porosity/permeability model of organic matter, inorganic matter and induced fractures, considering the water film in unstimulated reservoir volume (USRV) region water and bulk water in effectively stimulated reservoir volume (ESRV) region, a multi-media water-gas two-phase flow model was established. The finite difference is used to solve the model and the water-gas two-phase flow behavior of multi-fractured horizontal wells is obtained. Mass transfer between different-scale media, the effects of pore pressure on reservoirs and fluid properties at different production stages were considered in this model. The influence of the dynamic reservoir physical parameters on flow behavior and gas production in multi-fractured horizontal wells is studied. The results show that the properties of the total organic content (TOC) and the inherent porosity of the organic matter affect gas production after 40 days. With the gradual increase of production time, the gas production rate decreases rapidly compared with the water production rate, and the gas saturation in the inorganic matter of the ESRV region gradually decreases. The ignorance of stress sensitivity would cause the gas production increase, and the ignorance of organic matter shrinkage decrease the gas production gradually. The water film mainly affects gas production after 100 days, while the bulk water has a greater impact on gas production throughout the whole period. The research provides a new method to accurately describe the two-phase fluid flow behavior in different scale media of fractured shale gas reservoirs.

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