› › Using Rate Transient Analysis And Bayesian Algorithms For Reservoir Characterization In Hydraulically Fractured Horizontal Gas Wells During Linear Flow

Using Rate Transient Analysis and Bayesian Algorithms for Reservoir Characterization in Hydraulically Fractured Horizontal Gas Wells During Linear Flow

Author : Pirayu Yuhun

Publisher :

Page : 196 pages

File Size : 41,30 MB

Release : 2019

Category : Bayesian field theory

ISBN :

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Book Description

Multi-stage hydraulically fractured horizontal wells (MFHWs) are currently a popular method of developing shale gas and oil reservoirs. The performance of MFHWs can be analyzed by an approach called Rate transient analysis (RTA). However, the predicted outcomes are often inaccurate and provide non-unique results. Therefore, the main objective of this thesis is to couple Bayesian Algorithms with a current production analysis method, that is, rate transient analysis, to generate probabilistic credible interval ranges for key reservoir and completion variables. To show the legitimacy of the RTA-Bayesian method, synthetic production data from a multistage hydraulically fractured horizontal completion in a reservoir modeled after Marcellus shale reservoir was generated using a reservoir (CMG) model. The synthetic production data was analyzed using a combination of rate transient analysis with Bayesian techniques. Firstly, the traditional log-log plot was produced to identify the linear flow production regime, which is usually the dominant regime in shale reservoirs. Using the linear flow production data and traditional rate transient analysis equations, Bayesian inversion was carried out using likelihood-based and likelihood-free Bayesian methods. The rjags and EasyABC packages in statistical software R were used for the likelihood-based and likelihood-free inversion respectively. Model priors were based (1) on information available about the Marcellus shale from technical literature and (2) hydraulic fracture design parameters. Posterior distributions and prediction intervals were developed for the fracture length, matrix permeability, and skin factor. These predicted credible intervals were then compared with actual synthetic reservoir and hydraulic fracture data. The methodology was also repeated for an actual case in the Barnett shale for a validation. The most substantial finding was that for all the investigated cases, including complicated scenarios (such as finite fracture conductivity, fracturing fluid flowback, heterogeneity of fracture length, and pressure-dependent reservoir), the combined RTA-Bayesian model provided a reasonable prediction interval that encompassed the actual/observed values of the reservoir/hydraulic fracture variables. The R-squared value of predicted values over true values was more than 0.5 in all cases. For the base case in this study, the choice of the prior distribution did not affect the posterior distribution/prediction interval in a significant manner in as much as the prior distribution was partially informative. However, the use of noninformative priors resulted in a loss of precision. Also, a comparison of the Approximate Bayesian Computation (ABC) and the traditional Bayesian algorithms showed that the ABC algorithm reduced computational time with minimal loss of accuracy by at least an order of magnitude by bypassing the complicated step of having to compute the likelihood function. In addition, the production time, number of iterations and tolerance of fitting had a minimal impact on the posterior distribution after an optimum point--which was at least one-year production, 10,000 iterations and 0.001 respectively. In summary, the RTA-Bayesian production analysis method implemented in relatively easy computational platforms, like R and Excel, provided good characterization of all key variables such as matrix permeability, fracture length and skin when compared to results obtained from analytical methods. This probabilistic characterization has the potential to enable better understanding of well performance, improved identification of optimization opportunities and ultimately improved ultimate recovery from shale gas resources.





Unconventional Reservoirs: Rate and Pressure Transient Analysis Techniques

Author : Amin Taghavinejad

Publisher : Springer Nature

Page : 119 pages

File Size : 19,95 MB

Release : 2021-09-13

Category : Technology & Engineering

ISBN : 3030828379

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Book Description

This book provides a succinct overview on the application of rate and pressure transient analysis in unconventional petroleum reservoirs. It begins by introducing unconventional reservoirs, including production challenges, and continues to explore the potential benefits of rate and pressure analysis methods. Rate transient analysis (RTA) and pressure transient analysis (PTA) are techniques for evaluating petroleum reservoir properties such as permeability, original hydrocarbon in-place, and hydrocarbon recovery using dynamic data. The brief introduces, describes and classifies both techniques, focusing on the application to shale and tight reservoirs. Authors have used illustrations, schematic views, and mathematical formulations and code programs to clearly explain application of RTA and PTA in complex petroleum systems. This brief is of an interest to academics, reservoir engineers and graduate students.



Unconventional Reservoir Rate-Transient Analysis

Author : Christopher R. Clarkson

Publisher : Gulf Professional Publishing

Page : 1144 pages

File Size : 46,32 MB

Release : 2021-06-15

Category : Science

ISBN : 0323901174

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Book Description

Unconventional Reservoir Rate-Transient Analysis provides petroleum engineers and geoscientists with the first comprehensive review of rate-transient analysis (RTA) methods as applied to unconventional reservoirs. Volume One—Fundamentals, Analysis Methods, and Workflow is comprised of five chapters which address key concepts and analysis methods used in RTA. This volume overviews the fundamentals of RTA, as applied to low-permeability oil and gas reservoirs exhibiting simple reservoir and fluid characteristics.Volume Two—Application to Complex Reservoirs, Exploration and Development is comprised of four chapters that demonstrate how RTA can be applied to coalbed methane reservoirs, shale gas reservoirs, and low-permeability/shale reservoirs exhibiting complex behavior such as multiphase flow. Use of RTA to assist exploration and development programs in unconventional reservoirs is also demonstrated. This book will serve as a critical guide for students, academics, and industry professionals interested in applying RTA methods to unconventional reservoirs. - Gain a comprehensive review of key concepts and analysis methods used in modern rate-transient analysis (RTA) as applied to low-permeability ("tight") oil and gas reservoirs - Improve your RTA methods by providing reservoir/hydraulic fracture properties and hydrocarbon-in-place estimates for unconventional gas and light oil reservoirs exhibiting complex reservoir behaviors - Understand the provision of a workflow for confident application of RTA to unconventional reservoirs



Study of Flow Regimes in Multiply-fractured Horizontal Wells in Tight Gas and Shale Gas Reservoir Systems

Author : Craig Matthew Freeman

Publisher :

Page : pages

File Size : 14,89 MB

Release : 2010

Category :

ISBN :

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Book Description

Various analytical, semi-analytical, and empirical models have been proposed to characterize rate and pressure behavior as a function of time in tight/shale gas systems featuring a horizontal well with multiple hydraulic fractures. Despite a small number of analytical models and published numerical studies there is currently little consensus regarding the large-scale flow behavior over time in such systems. The purpose of this work is to construct a fit-for-purpose numerical simulator which will account for a variety of production features pertinent to these systems, and to use this model to study the effects of various parameters on flow behavior. Specific features examined in this work include hydraulically fractured horizontal wells, multiple porosity and permeability fields, desorption, and micro-scale flow effects. The theoretical basis of the model is described in Chapter I, along with a validation of the model. We employ the numerical simulator to examine various tight gas and shale gas systems and to illustrate and define the various flow regimes which progressively occur over time. We visualize the flow regimes using both specialized plots of rate and pressure functions, as well as high-resolution maps of pressure distributions. The results of this study are described in Chapter II. We use pressure maps to illustrate the initial linear flow into the hydraulic fractures in a tight gas system, transitioning to compound formation linear flow, and then into elliptical flow. We show that flow behavior is dominated by the fracture configuration due to the extremely low permeability of shale. We also explore the possible effect of microscale flow effects on gas effective permeability and subsequent gas species fractionation. We examine the interaction of sorptive diffusion and Knudsen diffusion. We show that microscale porous media can result in a compositional shift in produced gas concentration without the presence of adsorbed gas. The development and implementation of the micro-flow model is documented in Chapter III. This work expands our understanding of flow behavior in tight gas and shale gas systems, where such an understanding may ultimately be used to estimate reservoir properties and reserves in these types of reservoirs.



Novel Probabilistic-based Framework for Improved History Matching of Shale Gas Reservoirs

Author : Francis Nzubechukwu Nwabia

Publisher :

Page : 0 pages

File Size : 18,24 MB

Release : 2022

Category : Hydraulic fracturing

ISBN :

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Book Description

Hydraulically fractured horizontal wells are widely adopted for the development of tight or shale gas reservoirs. The presence of highly heterogeneous, multi-scale, fracture systems often renders any detailed characterization of the fracture properties challenging. The discrete fracture network (DFN) model offers a viable alternative for explicit representation of multiple fractures in the domain, where the comprising fracture properties are defined in accordance with specific probability distributions. However, even with the successful modelling of a DFN, the relationship between a set of fracture parameters and the corresponding production performance is highly nonlinear, implying that a robust history-matching workflow capable of updating the pertinent DFN model parameters is required for calibrating stochastic reservoir models to both geologic and dynamic production data. This thesis will develop an integrated approach for the history matching of hydraulically fractured reservoirs. First, multiple realizations of the DFN model are constructed with conditioning data based on available geological information such as seismic data, well logs, and rate transient analysis (RTA) interpretations, which are useful for inferring the prior probability distributions of relevant fracture parameters. A pilot point scheme and sequential indicator simulation are employed to update the distributions of fracture intensities which represent the abundance of secondary fractures (NFs) in the entire reservoir volume. Next, the model realizations are upscaled into an equivalent continuum dual-porosity dual-permeability model and subjected to numerical multiphase flow simulation. The predicted production performance is compared with the actual recorded responses. Finally, the DFN-model parameters are adjusted following an indicator-based probability perturbation method. Although the probability perturbation technique has been applied to update facies distributions in the past, its application in modeling DFN distributions is limited. An indicator formulation is proposed to account for the non-Gaussian nature of the DFN parameters. The algorithm aims at minimizing the objective function while reducing the uncertainties in the unknown fracture parameters. The novel probabilistic-based framework is applied to estimate the posterior probability distributions of transmissivity of the primary fracture (Tpf), transmissivity of the secondary induced fracture (Tsf) and secondary fracture intensity (Psf32L), secondary fracture aperture (re), length and height (L and H), in a multifractured shale gas well in the Horn River Basin. An initial realization of the DFN model is sampled from the prior probability distributions using the Monte Carlo simulation. These probability distributions are updated to match the production history, and multiple realizations of the DFN models are sampled from the updated (posterior) distributions accordingly. The key novelty in the developed probabilistic approach is that it accounts for the highly nonlinear relationships between fracture model parameters and the corresponding flow responses, and it yields an ensemble of DFN realizations calibrated to both static and dynamic data, as well as the related upscaled flow-simulation models. The results demonstrate the utility of the developed approach for estimating secondary fracture parameters, which are not inferable from other static information alone.



The Implications and Flow Behavior of the Hydraulically Fractured Wells in Shale Gas Formation

Author : Anas Mohammadali S. Almarzooq

Publisher :

Page : pages

File Size : 49,1 MB

Release : 2012

Category :

ISBN :

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Book Description

Shale gas formations are known to have low permeability. This low permeability can be as low as 100 nano darcies. Without stimulating wells drilled in the shale gas formations, it is hard to produce them at an economic rate. One of the stimulating approaches is by drilling horizontal wells and hydraulically fracturing the formation. Once the formation is fractured, different flow patterns will occur. The dominant flow regime observed in the shale gas formation is the linear flow or the transient drainage from the formation matrix toward the hydraulic fracture. This flow could extend up to years of production and it can be identified by half slop on the log-log plot of the gas rate against time. It could be utilized to evaluate the hydraulic fracture surface area and eventually evaluate the effectiveness of the completion job. Different models from the literature can be used to evaluate the completion job. One of the models used in this work assumes a rectangular reservoir with a slab shaped matrix between each two hydraulic fractures. From this model, there are at least five flow regions and the two regions discussed are the Region 2 in which bilinear flow occurs as a result of simultaneous drainage form the matrix and hydraulic fracture. The other is Region 4 which results from transient matrix drainage which could extend up to many years. The Barnett shale production data will be utilized throughout this work to show sample of the calculations. This first part of this work will evaluate the field data used in this study following a systematic procedure explained in Chapter III. This part reviews the historical production, reservoir and fluid data and well completion records available for the wells being analyzed. It will also check for data correlations from the data available and explain abnormal flow behaviors that might occur utilizing the field production data. It will explain why some wells might not fit into each model. This will be followed by a preliminary diagnosis, in which flow regimes will be identified, unclear data will be filtered, and interference and liquid loading data will be pointed. After completing the data evaluation, this work will evaluate and compare the different methods available in the literature in order to decide which method will best fit to analyze the production data from the Barnett shale. Formation properties and the original gas in place will be evaluated and compared for different methods.





Pressure Transient Analysis and Production Analysis for New Albany Shale Gas Wells

Author : Bo Song

Publisher :

Page : pages

File Size : 35,54 MB

Release : 2010

Category :

ISBN :

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Book Description

Shale gas has become increasingly important to United States energy supply. During recent decades, the mechanisms of shale gas storage and transport were gradually recognized. Gas desorption was also realized and quantitatively described. Models and approaches special for estimating rate decline and recovery of shale gas wells were developed. As the strategy of the horizontal well with multiple transverse fractures (MTFHW) was discovered and its significance to economic shale gas production was understood, rate decline and pressure transient analysis models for this type of well were developed to reveal the well behavior. In this thesis, we considered a 0́Triple-porosity/Dual-permeability0́+ model and performed sensitivity studies to understand long term pressure drawdown behavior of MTFHWs. A key observation from this study is that the early linear flow regime before interfracture interference gives a relationship between summed fracture half-length and permeability, from which we can estimate either when the other is known. We studied the impact of gas desorption on the time when the pressure perturbation caused by production from adjacent transference fractures (fracture interference time) and programmed an empirical method to calculate a time shift that can be used to qualify the gas desorption impact on long term production behavior. We focused on the field case Well A in New Albany Shale. We estimated the EUR for 33 wells, including Well A, using an existing analysis approach. We applied a unified BU-RNP method to process the one-year production/pressure transient data and performed PTA to the resulting virtual constant-rate pressure drawdown. Production analysis was performed meanwhile. Diagnosis plots for PTA and RNP analysis revealed that only the early linear flow regime was visible in the data, and permeability was estimated both from a model match and from the relationship between fracture half-length and permeability. Considering gas desorption, the fracture interference will occur only after several centuries. Based on this result, we recommend a well design strategy to increase the gas recovery factor by decreasing the facture spacing. The higher EUR of Well A compared to the vertical wells encourages drilling more MTFHWs in New Albany Shale.



Data Bias in Rate Transient Analysis of Shale Gas Wells

Author : Ammar Khalifa Mohammed Agnia

Publisher :

Page : pages

File Size : 22,86 MB

Release : 2012

Category :

ISBN :

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Book Description

Superposition time functions offer one of the effective ways of handling variable-rate data. However, they can also be biased and misleading the engineer to the wrong diagnosis and eventually to the wrong analysis. Since the superposition time functions involve rate as essential constituent, the superposition time is affected greatly with rate issues. Production data of shale gas wells are usually subjected to operating issues that yield noise and outliers. Whenever the rate data is noisy or contains outliers, it will be hard to distinguish their effects from common regime if the superposition time functions are used as plotting time function on log-log plots. Such deceiving presence of these flow regimes will define erroneous well and reservoir parameters. Based on these results and with the upsurge of energy needs there might be some costly decisions will be taken such as refracting or re-stimulating the well especially in tight formations. In this work, a simple technique is presented in order to rapidly check whether there is data bias on the superposition-time specialized plots or not. The technique is based on evaluating the kernel of the superposition time function of each flow regime for the maximum production time. Whatever beyond the Kernel-Equivalent Maximum Production Time (KEMPT) it is considered as biased data. The hypothesis of this technique is that there is no way to see in the reservoir more than what has been seen. A workflow involving different diagnostic and filtering techniques has been proposed to verify proposed notion. Different synthetic and field examples were used in this study. Once the all problematic issues have been detected and filtered out, it was clear that whatever went beyond the KEMPT is a consequence of these issues. Thus, the proposed KEMPT technique can be relied on in order to detect and filter out the biased data points on superposition-time log-log plots. Both raw and filtered data were analyzed using type-curve matching of linear flow type-curves for calculating the original gas in-place (OGIP). It has been found that biased data yield noticeable reduced OGIP. Such reduction is attributed to the early fictitious onset of boundary dominated flow, where early false detection of the drainage boundaries defines less gas in-place occupied in these boundaries.