scholarly journals Development of Shale Gas Prediction Models for Long-Term Production and Economics Based on Early Production Data in Barnett Reservoir

Energies ◽  
2020 ◽  
Vol 13 (2) ◽  
pp. 424 ◽  
Author(s):  
Viet Nguyen-Le ◽  
Hyundon Shin ◽  
Edward Little
Keyword(s):  
Shale Gas ◽  
Net Present Value ◽  
Prediction Models ◽  
Input Parameter ◽  
Gas Production ◽  
Barnett Shale ◽  
Production Data ◽  
Production History ◽  
Early Production

This study examined the relationship between the early production data and the long-term performance of shale gas wells, including the estimated ultimate recovery (EUR) and economics. The investigated early production data are peak gas production rate, 3-, 6-, 12-, 18-, and 24-month cumulative gas production (CGP). Based on production data analysis of 485 reservoir simulation datasets, CGP at 12 months (CGP_12m) was selected as a key input parameter to predict a long-term shale gas well’s performance in terms of the EUR and net present value (NPV) for a given well. The developed prediction models were then validated using the field production data from 164 wells which have more than 10 years of production history in Barnett Shale, USA. The validation results showed strong correlations between the predicted data and field data. This suggests that the proposed models can predict the shale gas production and economics reliably in Barnett shale area. Only a short history of production (one year) can be used to estimate the EUR and NPV of various production periods for a gas well. Moreover, the proposed prediction models are consistently applied for young wells with short production histories and lack of reservoir and hydraulic fracturing data.

scholarly journals An Analytical Method for Parameter Interpretation of Fracture Networks in Shale Gas Reservoirs considering Uneven Support of Fractures

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-15
Author(s):  
Shijun Huang ◽  
Jiaojiao Zhang ◽  
Sidong Fang ◽  
Xifeng Wang
Keyword(s):  
Data Analysis ◽  
Shale Gas ◽  
Analytical Method ◽  
Material Balance ◽  
Gas Production ◽  
Production Data ◽  
Analysis Method ◽  
Gas Reservoirs ◽  
Data Analysis Method ◽  
Parameter Interpretation

In shale gas reservoirs, the production data analysis method is widely used to invert reservoir and fracture parameter, and productivity prediction. Compared with numerical models and semianalytical models, which have high computational cost, the analytical model is mostly used in the production data analysis method to characterize the complex fracture network formed after fracturing. However, most of the current calculation models ignore the uneven support of fractures, and most of them use a single supported fracture model to describe the flow characteristics, which magnifies the role of supported fracture to a certain extent. Therefore, in this study, firstly, the fractures are divided into supported fractures and unsupported fractures. According to the near-well supported fractures and far-well unsupported fractures, the SRV zone is divided into outer SRV and inner SRV. The four areas are characterized by different seepage models, and the analytical solutions of the models are obtained by Laplace transform and inverse transform. Secondly, the material balance pseudotime is introduced to process the production data under the conditions of variable production and variable pressure. The double logarithmic curves of normalized production rate, rate integration, the derivative of the integration, and material balance pseudotime are established, and the parameters are interpreted by fitting the theoretical curve to the measured data. Then, the accuracy of the method is verified by comparison the parameter interpretation results with well test results, and the influence of parameters such as the half-length and permeability of supported and unsupported fractures on gas production is analyzed. Finally, the proposed method is applied to four field cases in southwest China. This paper mainly establishes an analytical method for parameter interpretation after hydraulic fracturing based on the production data analysis method considering the uneven support of fractures, which is of great significance for understanding the mechanism of fracturing stimulation, optimization of fracturing parameters, and gas production forecast.

scholarly journals Shale gas production decline trend over time in the Barnett Shale

2018 ◽  
Vol 165 ◽  
pp. 691-710 ◽  
Author(s):  
Michael Kenomore ◽  
Mohamed Hassan ◽  
Reza Malakooti ◽  
Hom Dhakal ◽  
Amjad Shah
Keyword(s):  
Shale Gas ◽  
Gas Production ◽  
Barnett Shale ◽  
Over Time

Modeling Two-Phase Flowback of Multifractured Horizontal Wells Completed in Shale

SPE Journal ◽  
2013 ◽  
Vol 18 (04) ◽  
pp. 795-812 ◽  
Author(s):  
C.R.. R. Clarkson ◽  
J.D.. D. Williams-Kovacs
Keyword(s):  
Shale Gas ◽  
Transient Analysis ◽  
Horizontal Wells ◽  
Production Data ◽  
Two Phase ◽  
Fracture Properties ◽  
Rate Transient Analysis ◽  
Wellbore Storage ◽  
Fluid Production

Summary Early fluid production and flowing pressure data gathered immediately after fracture stimulation of multifractured horizontal wells may provide an early opportunity to generate long-term forecasts in shale-gas (and other hydraulically fractured) reservoirs. These early data, which often consist of hourly (if not more frequent) monitoring of fracture/formation fluid rates, volumes, and flowing pressures, are gathered on nearly every well that is completed. Additionally, fluid compositions may be monitored to determine the extent of load fluid recovery, and chemical tracers added during stage treatments to evaluate inflow from each of the stages. There is currently debate within the industry of the usefulness of these data for determining the long-term production performance of the wells. “Rules of thumb” derived from the percentage of load-fluid recovery are often used by the industry to provide a directional indication of well performance. More-quantitative analysis of the data is rarely performed; it is likely that the multiphase-flow nature of flowback and the possibility of early data being dominated by wellbore-storage effects have deterred many analysts. In this work, the use of short-term flowback data for quantitative analysis of induced-hydraulic-fracture properties is critically evaluated. For the first time, a method for analyzing water and gas production and flowing pressures associated with the flowback of shale-gas wells, to obtain hydraulic-fracture properties, is presented. Previous attempts have focused on single-phase analysis. Examples from the Marcellus shale are analyzed. The short (less than 48 hours) flowback periods were followed by long-term pressure buildups (approximately 1 month). Gas + water production data were analyzed with analytical simulation and rate-transient analysis methods designed for analyzing multiphase coalbed-methane (CBM) data. This analogy is used because two-phase flowback is assumed to be similar to simultaneous flow of gas and water during long-term production through the fracture system of coal. One interpretation is that the early flowback data correspond to wellbore + fracture volume depletion (storage). It is assumed that fracture-storage volume is much greater than wellbore storage. This flow regime appears consistent with what is interpreted from the long-term pressure-buildup data, and from the rate-transient analysis of flowback data. Assuming further that the complex fracture network created during stimulation is confined to a region around perforation clusters in each stage, one can see that fluid-production data can be analyzed with a two-phase tank-model simulator to determine fracture permeability and drainage area, the latter being interpreted to obtain an effective (producing) fracture half-length given geometrical considerations. Total fracture half-length, derived from rate-transient analysis of online (post-cleanup) data, verifies the flowback estimates. An analytical forecasting tool that accounts for multiple sequences of post-storage linear flow, followed by late-stage boundary flow, was developed to forecast production with flowback-derived parameters, volumetric inputs, matrix permeability, completion data, and operating constraints. The preliminary forecasts are in very good agreement with online production data after several months of production. The use of flowback data to generate early production forecasts is therefore encouraging, but needs to be tested for a greater data set for this shale play and for other plays, and should not be used for reserves forecasting.

Corrigendum to "Shale gas production decline trend over time in the Barnett Shale" [J. Petrol. Sci. Eng. 165 (2018) 691–710]

2018 ◽  
Vol 167 ◽  
pp. 627
Author(s):  
Michael Kenomore ◽  
Mohamed Hassan ◽  
Reza Malakooti ◽  
Hom Dhakal ◽  
Amjad Shah
Keyword(s):  
Shale Gas ◽  
Gas Production ◽  
Barnett Shale ◽  
Over Time

scholarly journals How Many Wells? Exploring the Scope of Shale Gas Production for Achieving Gas Self-Sufficiency in Poland

2021 ◽  
Author(s):  
Henrik Wachtmeister ◽  
Magdalena Kuchler ◽  
Mikael Höök
Keyword(s):  
Shale Gas ◽  
Energy Security ◽  
Gas Production ◽  
Barnett Shale ◽  
Well Production ◽  
Self Sufficiency ◽  
Production Experience ◽  
The Usa ◽  
National Energy Security ◽  
Do So

AbstractPoland has been estimated to possess large volumes of technically recoverable shale gas resources, which has raised national hopes for increasing energy security and building export capacity. In this paper, we aim to examine political claims and hopes that Poland could achieve natural gas self-sufficiency and even become a gas exporter by harnessing domestic shale potential. We do so by relying on well-by-well production experience from the Barnett Shale in the USA to explore what scope of shale gas extraction, in terms of the number of wells, would likely be required to achieve such national expectations. With average well productivity equal to the Barnett Shale, at least 420 wells per year would be necessary to meet the domestic demand of 20 Bcm in 2030. Adding Poland’s potential export capacity of five Bcm of gas per year would necessitate at least 540 wells per year. Such a significant amount of drilling and hydraulic fracturing would require reconsideration and verification of national energy security plans and expectations surrounding shale gas production. A more informed public debate on technical aspects of extraction would be required, as extensive fracking operations could potentially have implications in terms of environmental risks and local land-use conflicts.

scholarly journals Well Screen and Optimal Time of Refracturing: A Barnett Shale Well

2013 ◽  
Vol 2013 ◽  
pp. 1-10 ◽  
Author(s):  
Shayan Tavassoli ◽  
Wei Yu ◽  
Farzam Javadpour ◽  
Kamy Sepehrnoori
Keyword(s):  
Numerical Simulation ◽  
Shale Gas ◽  
Fracture Network ◽  
Gas Production ◽  
Sensitivity Analyses ◽  
Optimal Time ◽  
Barnett Shale ◽  
Vast Number ◽  
Access To Data ◽  
The Right

Gas-production decline in hydraulically fractured wells in shale formations necessitates refracturing. However, the vast number of wells in a field makes selection of the right well challenging. Additionally, the success of a refracturing job depends on the time to refracture a shale-gas well during its production life. In this paper we present a numerical simulation approach to development of a methodology for screening a well and to determine the optimal time of refracturing. We implemented our methodology for a well in the Barnett Shale, where we had access to data. The success of a refracturing job depends on reservoir characteristics and the initial induced fracture network. Systematic sensitivity analyses were performed so that the characteristics of a shale-gas horizontal well could be specified as to the possibility of its candidacy for a successful refracturing job. Different refracturing scenarios must be studied in detail so that the optimal design might be determined. Given the studied trends and implications for a production indicator, the optimal time for refracturing can then be suggested for the studied well. Numerical-simulation results indicate significant improvement (on the order of 30%) in estimated ultimate recovery (EUR) after refracturing, given presented screen criteria and optimal-time selection.

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