bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling 2-Phase Flowback of Multi-Fractured Horizontal Wells Completed in Shale
Authors: Clarkson C. R. 
Published: October 2012

Abstract
Early fluid production and flowing pressure data gathered immediately after fracture-stimulation of multi-fractured horizontal wells may provide an early opportunity to generate long-term forecasts in shale gas reservoirs. These early data, which often consists 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" based upon 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 multi-phase flow nature of flowback, and the possibility of early data being dominated by wellbore storage effects has deterred many analysts.
In this work, the use of short-term flowback data for quantitative analysis of induced hydraulic fracture properties is critically evaluated. Examples from the Marcellus shale are analyzed. The short (&lt; 48 hours) flowback periods were followed by long-term pressure build-ups (~1 month). Gas/water production data was analyzed using analytical simulation and rate-transient analysis methods designed for analyzing multi-phase coalbed methane (CBM) data. One interpretation is that the early flowback data corresponds 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 rate-transient analysis of flowback data. Assuming further that the complex fracture network created during stimulation is confined to a cylindrical region around perforation clusters in each stage, fluid production data can be analyzed using a 2-phase tank model simulator to determine fracture permeability and drainage radius, the latter being interpreted to be equivalent to effective (producing) fracture half-length. Total fracture half-length, derived from rate-transient analysis of on-line (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 using only flowback-derived parameters, volumetric inputs, matrix permeability, completion data and operating constraints. The preliminary forecasts are in very good agreement with on-line 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.
Practical Use of Simulators for Characterization of Shale Reservoirs
Authors: Alkouh Ahmad , Schechter David , Wattenbarger Robert A. , Patel K. 
Published: October 2012

Abstract
Shale gas/oil wells are a challenge due to the complex reservoirs and well completion designs. Commercial simulators with new automatic features play an important role in shale reservoir characterization. These commercial simulators include special features for modeling horizontal, multi-fracked shale wells with simplified user interfaces. The primary goal of this paper is to compare the simulation of transient and boundary dominated flow with analytical solutions through specialized rate function plots. These comparisons provide a straightforward means for testing the accuracy of automatic gridding features and the simulation methodology. If simulators can match idealized reservoirs accurately, then confidence improves in the matching of actual field cases that may vary from idealized reservoir behavior.
In this work, we tested the accuracy of these simulator features by making numerous simulation runs for various geological and geometric scenarios. We considered different simulation gridding and system models to correctly represent the transient linear flow and its effect on the analysis. Some general gridding rules were developed.
This work investigates the use of an effective permeability equation from analytical solution and its application to several wells in reservoirs located in the Bakken, Barnett, and Eagle Ford formations. Simulation was used to confirm the equation’s accuracy and to show its applicability in fractured shale reservoirs.
Results from this investigation should help engineers select the best automatic features to accurately represent shale wells and then cross check the results using the analytical solution. This study also expanded our understanding of flow behavior in production data which may be used to improve modeling shale wells for better agreement with the analytical solutions.
What's Positive About Negative Intercepts
Authors: Thompson J. M. , Liang P. , Mattar L. 
Published: October 2012

Abstract
The paradigm shift towards horizontal well drilling with multiple fracture stages to exploit unconventional plays has unsurprisingly resulted in a rapid growth of questions regarding the interpretation of the associated well performance signatures on log-log diagnostic and specialized analysis plots. Log-log diagnostic plots perhaps best illustrate the sequence of flow-regimes which may result from this completion type. However, the long-term behavior one should expect to see on a square-root-time plot from the sequence is seldom presented in the literature, in spite of the ubiquitous use of linear flow specialized plots for unconventional well performance analysis. This paper addresses frequently asked questions regarding the meaning of the commonly observed negative y-intercepts on these plots. Using multi-frac horizontal well analytical models, synthetic production data sets were generated to evaluate various hydraulic-fracture geometries. The resulting data signatures are presented on a dimensionless specialized plot to reveal the behavior of the early linear, transitional and (late) compound linear flow regimes. This study illustrates that negative intercepts are typically created from the transitional period following the first linear flow and quantifies both the magnitude and sign of the resulting intercept produced from compound linear flow based on various hydraulic fracture length and spacing combinations. Using a field example, this work also demonstrates that false interpretations of compound linear flow may arise due to the misinterpretation of the prolonged transitional flow period between the first and second linear flow regimes.
Comparison of Empirical Decline Curve Methods for Shale Wells
Authors: Kanfar Mohammed S , Wattenbarger R. A. 
Published: October 2012

Abstract
Analyzing shale wells using traditional decline curve methods is problematic because of the nature of reservoir properties and flow behavior in typical shale wells. New empirical methods were developed to model the special production decline of shales. These methods were formulated using different mathematical and statistical bases and result in different forecasts. Hence, engineers have a variety of methods that may give different estimates for ultimate recovery when analyzing shale wells. In this work, four recently developed decline curve methods, along with the traditional Arps method, were compared.
The four recent methods compared here were empirically formulated for shale wells and tight gas wells. They are: a) the Power Law Exponential Decline, b) the Stretched Exponential Decline, c) Duong’s Method, and d) the Logistic Growth Model. Each method has different tuning parameters and equation forms. In this work, the methods were programmed and automated by using nonlinear regression to match the production "history" of a well. In addition, they were compared in terms of "goodness of fit" to the history data and reliability of automation as well as production forecast and ultimate recovery estimation. These methods were compared with simulation models in addition to field data from Barnett Shale, Bakken Shale, and the Eagle Ford Shale.
Each of these methods may have application for different cases. It may be advisable to program each of these methods for optional usage in applications. But this current paper should allow engineers to understand better the characteristics of each method and to choose the method that best models their wells under various circumstances.
Sleeve Activation Sleeve Activation in Open-hole Fracturing Systems: A Ball Selection Study
Authors: Baihly Jason , Aviles Isaac , Johnson Joshua , Melenyzer George 
Published: October 2012

Abstract
During the past decade, the completion technique used in liquid-rich unconventional plays in North America has undergone a transformation. Today, the vast majority of completions in these areas are open-hole (OH) graduated ball-drop fracturing isolation systems. This preferred completion type for horizontal wells is driven by the efficiency gains in fracturing operations and the production gains when compared to previously used completion techniques. Thousands of open-hole fracturing systems are run each year, with a continuously growing stage count.
Graduated ball-drop type completions rely on a sliding sleeve activated by a ball dropped from surface. Each ball travels the length of the lateral well to its intended operational depth, at which it meets a mated seat and isolates the wellbore below. Once the ball is in position, the sliding sleeve opens via the hydraulic force on the ball and seat, allowing a fracturing stage to commence. This dual function of the ball—activation and sealing—is of extreme importance for the stimulation treatment process. If the ball fails, it will result in bypassed pay zones and unintentional refracturing of previously stimulated zones. Although sometimes surface pressures can be used to infer ball behavior, often the pressure signals observed at surface cannot guarantee successful ball performance.
This paper will present an extensive study of ball performance under pressure for the most common ball materials in the industry. Phenolic, composite and metal alloy materials were explored with the pros and cons for each investigated. In particular three main areas were analyzed: 1) molding, layering and extrusion of material versus inconsistencies in ball performance; 2) ball deformation at high pressure versus pressure required to bring the ball off seat; and 3) comparison of the performance of phenolic, composite and metal alloy materials for ball fabrication and their performance at high temperature.
The conclusions from this paper provide operators the necessary information to consider when making completion and ball material decisions in their field operations. In particular, the results of this testing may illuminate some previously unexplainable occurrences in graduated ball sliding-sleeve systems. This testing clarified that not all fracturing balls pumped in horizontal wells perform equivalently under wellbore fracture conditions.
Streamlined Completions Process: An Eagle Ford Shale Case History
Authors: Arguijo Andrew L. , Morford Lee , Baihly Jason , Aviles Isaac 
Published: October 2012

Abstract
The Eagle Ford shale is a hydrocarbon-producing formation of significant importance due to its capability for producing at high-liquid/gas ratios, more so than other traditional shale plays. Situated in south Texas, the total Eagle Ford liquids production in 2007 was less than 21,000 bbl total. In 2011, production averaged 65,500 BOPD in the play (EIA, 2011). Activity in the Eagle Ford continues to increase because the benefits from producing high liquid yields across much of the play, along with attractive commodity prices, have made the Eagle Ford a more attractive development over many other shale reservoirs.
The rapid development of the Eagle Ford shale was enabled by horizontal drilling. In 2007 none of the reported production was from horizontal wells. In 2011 alone over 2,800 drilling permits were issued, virtually all of them for horizontal wells (RigData, 2012). The Eagle Ford shale has low-clay content, high-carbonate content, and is in an extensional basin, making it conducive to somewhat complex hydraulic fracturing (Martin et al, 2011). The plug and perforating technique has become the preferred completion method in the play due to multiple entry points creating complex fractures at a minimal cost. This completion technique requires a mechanical means for conveying perforating guns, such as coiled tubing (CT), wireline tractor or stick pipe, for the first fracturing stage at the toe of the well.
To streamline their completion process, an Eagle Ford operator chose to use an initiator valve that is run at the toe of the well as part of the final completion design. This pressure activated valve is capable of initiating operations on the first fracturing stage without the need for CT or other mechanical means of conveyance of perforating guns. Simple and robust, the valve is activated by a pressure increase from the surface. The valve uses a rupture disc for precise activation and a helical port design that allows for hydraulic fracturing to be performed through the valve into the cement and the formation. With over a dozen wells completed in the Eagle Ford formation by the operator, the valve has provided logistical and economic benefits to the streamlined completion process.
This paper describes the initiator valve completion tool and its application in the Eagle Ford shale. A case history is presented to show the specific design and operation of the initiator valve, as well as its benefits over other completion practices that target the first stage in a closed lateral system. Detailed activation of the valve and fracturing data through the valve are also presented.
Considerations for Pore Volume Stress Effects in Over-pressured Shale Gas under Controlled Drawdown Well Management Strategy
Authors: Akande Jesse , Spivey J. P. 
Published: October 2012

Abstract
The high decline rate observed in over pressured shale has attracted the attention of the industry, and better well management procedures for long term productivity improvement are still evolving. Operators are recognizing some benefit in controlled rate (controlled drawdown) production as one way of improving well performance for the wells in over pressured stress sensitive formations.
During uncontrolled rate production because of high drawdown, the permeability in stress sensitive shales decays faster because of increased stress. Often high initial gas rate is accompanied by high decline rate as the permeability reduction takes effect. In addition, proppant could also be produced back, crushed or embedded in the formation. However, controlled rate production minimizes the rate decline, albeit at reduced initial gas rate. Modelers resort to using different stress permeability decay coefficients for these two production strategies. Higher values are assigned to uncontrolled rate production to produce lower EUR. This approach, although convenient, requires different permeability versus stress tables depending on the production strategy.
Porosity and pore volume reduction in shales could be as high as 20 percent due to changes in net stress. The pore volume reduction provides in situ energy for gas recovery. The increased rate of permeability decay due to changing in situ stresses reduces the effectiveness of pressure support from pore volume reduction as fractures close under stress.. Controlled rate production strategy slows down permeability decay rate and this enables better use of pore volume energy. The pore volume consideration could provide additional gain to EUR for controlled rate.
Our analytical simulation model couples geomechanics permeability and porosity stress coefficients and evaluates well performance under moderate and low net stress sensitivity. Haynesville and Marcellus shales were evaluated. The importance of pore volume stress effect from the stand point of well performance evaluation and reservoir characterization is assessed.
Innovative Nanoparticle Drilling Fluid and Its Benefits to Horizontal or Extended Reach Drilling
Authors: Hareland Geir , Wu Andrew , Lei Lingyun , Husein Maen M. , Zakaria Mohammad F. 
Published: October 2012

Abstract
Development of new exploration, drilling and completion technologies in the past two decades have led to the opening of new plays in North America targeting unconventional resources. Lots of innovative drilling fluids have been developed and applied in the drilling and completion engineering. The demands encountered drilling highly deviated wells include the effective control of torque and drag. Therefore one of the applications of the innovative drilling fluids is to lower friction coefficient between drillstring and wellbore, which will reduce the drag and make it possible to drill longer horizontal or extended distances during horizontal or extended reach wells.
This paper first briefly introduces the problems from the drag when drilling horizontal or extended reach wells, calculation of torque and drag with analytical models and the shortcomings of those models. Then addresses how the lower friction coefficient from the innovative fluid will bring benefit to the horizontal or extended reach drilling, where finite element method (FEM) is introduced to analyze the interaction between the wellbore and drillstring. Finally three case studies are detailed and results are also analyzed.
The three examples are calculating the drag and torque along the entire drillstring, comparing the drag and torque with different friction coefficients with constant torque, buoyancy and downhole weight on bit, and obtaining the increment of horizontal section when using the innovative drilling fluid. The tension or compression force distribution along the entire drillstring is clearly shown through graphs or plotting. The results and analysis with FEM show that the low friction coefficient from the innovative drilling fluid has a great benefit in horizontal or extended reach drilling, increasing the current rig and equipment reach limit substantially.
The analysis method presented in this paper can provide a solid base for drilling engineers so that they can accurately estimate the extended reach with this new drilling fluid. It will improve the drilling efficiency and reduce the total cost, especially in unconventional well drilling in that less and longer wells can be used to drain the reservoirs.
New Advances in Production Data Analysis of Hydraulically Fractured Tight Reservoirs
Authors: Siddiqui Shahab K. , Ali Afsar , Dehghanpour Hassan 
Published: October 2012

Abstract
Tight reservoirs stimulated by multistage hydraulic fracturing are commonly described by a dual porosity model. This model consists of homogeneous matrix blocks separated by vertical hydraulic fractures. This paper hypothesizes that the production data of some fractured horizontal wells may also be described by a triple porosity model. The third medium can be either reactivated natural fractures or thin horizontal beds with a higher permeability. We test this hypothesis by extending the existing triple porosity models to develop an analytical procedure for determining the reservoir parameters. We derive the simplified equations for different regions of the rate-time plot including linear and bilinear flow regions. These equations can be used to calculate the effective fracture half-length, matrix permeability and length of micro-fractures. We use the proposed model to analyze the production data of two wells drilled in Barnett shale. The results show that a dual porosity model is more appropriate for describing Barnett shale data. Even if the micro-fractures are present they are not inter-connected and the length scale is much smaller than the hydraulic fracture spacing.
The second part of this paper focuses on analyzing production data of tight oil reservoirs. We plot rate-normalized pressure (RNP) versus material balance time (MBT) of two wells drilled in Cardium and Bakken formations. We observe a half-slope followed by a unit-slope in both cases. This paper hypothesizes that the half slope reflects the linear transient flow regime, and the unit slope reflects the linear pseudosteady state (PSS) flow. We test this hypothesis by developing a new model for pseudo steady state flow when pressure interference occurs between two adjacent hydraulic fractures. We determine the reservoir properties by both PSS and transient analysis methods. For Cardium well, both methods give very close results. For Bakken well, both methods give relatively close results. We conclude that analyzing the late time production data of tight oil wells complement the linear transient analysis and can be used to calculate the stimulated reservoir volume, which can eventually help the industry to optimize the fracturing operation.