bluuebunny/crossref_metadata_2025_split huggingface dataset:
Shear Sensitivity of Borate Fracturing Fluids
Authors: Bjornen Kevin H. , Hodge Richard M. , Cawiezel Kay E. , England Kevin W. 
Published: September 2011

Abstract
Borate-crosslinked fracturing fluids have been used in the oil and gas industry for nearly 40 years. These fluids consist of three basic components (polymer, crosslinker, and pH buffer) which are considered relatively simple to optimize for a variety of field applications. Among the unique features of this fluid is the ability of the crosslink viscosity to "re-heal" or "recover" after exposure to high shear rates. Based on laboratory tests described in SPE 134266, it was determined that the "re-healing" time can be excessive for some borate-crosslinked fluids exposed to high shear, resulting in limited near-wellbore viscosity and screen-outs in the field.
Using a laboratory-scale flow loop to simulate the wellbore shear environment, various borate-crosslinked fluids were exposed to a wide range of shear history conditions before loading into a high temperature, high pressure rheometer. In addition to the common viscosity versus time profile, the early-time viscosity development of each fluid was analyzed to quantify the effect of shear history on recovery time.
This paper defines critical shear rates and exposure times that adversely impact early-time viscosity development of borate-crosslinked fracturing fluids. Also, the test results show that the impact of wellbore shear conditions on recovery time can be minimized by adjusting the concentration of the polymer, borate crosslinker, and/or pH buffer.
The techniques and guidelines provided in this paper can be used to identify detrimental wellbore shear conditions that will lead to excessive recovery times. The paper also demonstrates optimizing borate-crosslinked fluids with common on-site tests can result in fluid compositions with increased shear sensitivity.
A New Analytical Method for Analyzing Production Data from Shale Gas Reservoirs Exhibiting Linear Flow: Constant Rate Production
Authors: Nobakht M. , Clarkson C.R. 
Published: September 2011

Abstract
Hydraulically-fractured vertical and horizontal wells completed in shale gas and some tight gas plays are known to exhibit long periods of linear flow. Recently, techniques for analyzing this flow period using (normalized) production data have been put forth, but there are known errors associated with the analysis. In this paper, linear flow from fractured wells completed in tight/shale gas reservoirs, subject to a constant production rate constraint, is studied. It is shown analytically that the square root-time plot, a plot of rate-normalized pressure versus square root of time which is commonly used to interpret linear flow, depends on the production rate. It is also shown that depending on production rate, the square root-time plot may not be a straight line during linear flow; the higher the production rate the earlier in time the plot deviates from the expected straight line. This deviation creates error in the analysis. To address this issue, a new analytical method is developed for analyzing linear flow data for the constant gas rate production constraint. The method is then validated using a number of numerically-simulated cases. As expected, based on the analytical derivation, the square root-time plots for these cases depend on gas production rate and for some cases it does not appear as a straight line during linear flow. Finally, it is found that there is excellent agreement between the fracture half-lengths obtained using this method and the input fracture half-lengths to numerical simulation.
Advancements in Downhole Drilling Tool Placement for Highly Deviated Wells and ERD Applications
Authors: Bouaziz Souhail , Cummings Jerry , Rebellon Jorge , Barton Steve , Yankow Anna 
Published: September 2011

Abstract
With the discovery of shale plays around the world, there has been an increase in the prevalence of highly deviated wells and extended reach drilling. Both highly deviated wells and extended reach drilling present drilling challenges; modeling is required at various stages of the well and several considerations must be taken into account. In addition, detailed torque and drag analysis along with a comprehensive analysis of hydraulics programs must be performed to ensure the down hole equipment used for the application meets the challenging requirements. One of the most important considerations that should be taken into account is jar placement.
The intricacies of jar placement are typically misunderstood and often over-looked. Good, sound technical recommendations on jar placement are generally hard to come by. Yet, legitimate technical advice on jar placement can ultimately ensure the use of optimal operational guidelines when drilling in highly deviated wells and using extended reach drilling. In these instances, conventional jar placement knowledge does not always apply.
Highly deviated wells and extended reach drilling present unique drilling challenges such as the possibility of getting stuck in two different sections of the well bore. Computer modeling is currently used to predict any down hole loads that would hinder the operation of a drilling jar used in such an instance. This paper provides an analysis of jar placement in highly deviated wells and promotes the use of two drilling jars in the drill string. In addition, consideration is given to jar placement calculations which are further discussed in order to provide optimal impact and impulse result recommendations. A set of operational guidelines also has been included, ensuring that optimal results are obtained when using two jars in the drill string.
A Novel Screening Method for Selection of Horizontal Refracturing Candidates in Shale Gas Reservoirs
Authors: Sinha Shekhar , Ramakrishnan Hariharan 
Published: September 2011

Abstract
A novel method to rapidly screen potential horizontal refracturing candidates utilizing production performance and completion data analysis is presented. Candidate selection methods based solely on production comparison analysis are not very effective (Reeves, 2000). Integration of initial hydraulic fracture completion details augments the process and helps in screening understimulated wells in different production classes. To accomplish this, a new index called a "completion index" is defined after analysis of the completion parameters, production behavior and their inter-relationship. Typically, a completion index will be based on the well completion and stimulation job parameters, such as completion type, fluid volume, proppant volume, completed interval length, number of stages etc. The production index is a time normalized production indicator representative of longer-term production or expected ultimate recovery. A crossplot of production indicators and the completion index is used in the initial screening of potential candidates.
This method enables fast and efficient screening of wells with a below- average completion index and similar production index from thousands of wells. The screened candidates can then be taken to a higher tier of analysis that integrates the production performance and completion information with available petro-physical data and geological information. A reservoir quality indicator along the horizontal laterals can be extracted from the reservoir model and analyzed with completion index to better understand the production drivers.
Based on the data sets studied from Barnett shale areas it was possible to rapidly shortlist 15–20% of the wells from a large well population for further detailed analysis. Wells with an average and higher production index with below average completion index proved to be better candidates in terms of economic payout.
Submicron-Pore Characterization of Shale Gas Plays
Authors: Elgmati Malek , Zhang Hao , Bai Baojun , Flori Ralph , Qu Qi 
Published: September 2011

Abstract
Gas storage and flow behavior in the shale gas rocks are complex and hard to identify by conventional core analysis. This study integrates clustering analysis techniques from material science, petrophysics, and petrology to characterize North American shale gas samples from Utica, Haynesville, and Fayetteville shale gas plays. High pressure (up to 60,000 psi) mercury porosimetry analysis (MICP) determined the pore size distributions. A robust, detailed tomography procedure using a dual-beam (Scanning Electron Microscope and Focused Ion Beam, also called SEM-FIB) instrument successfully characterized the submicron-pore structures. SEM images revealed various types of porosities. Pores on a scale of nanometers were found in organic matter; they occupy 40–50% of the kerogen body. Two-hundred two-dimensional SEM images were collected and stacked to reconstruct the original pore structure in a three-dimensional model. The model provided insights into the petrophysical properties of shale gas, including pore size distribution, porosity, tortuosity, and anisotropy. This paper presents the pore model constructed from Fayetteville shale sample. The work used X-ray diffraction (XRD) to semi-quantify shale gas clay and non-clay minerals. The Haynesville and Utica (Indian Castle formation) shale samples have a high illite content. The Utica (Dolgeville formation) shale samples show high calcium carbonate (calcite) content. Moreover, wettability tests were performed on the shale samples, and the effect of various fracturing fluid additives on their wettability was tested. Most additives made the shale gas surfaces hydrophilic-like (water-wet).
Applying Real Time Well Performance Monitoring to a Mature Asset in Gabon: Case Study, Operational Feedback and Lessons Learned for Upcoming Deployments
Authors: Gibert Gaël , Simba-Ngabi Marcellin , Lestage Jean-Renaud 
Published: September 2011

Abstract
This paper describes the process of development, deployment and operation of an in-house integrated real time solution for Well Performance Monitoring (WPM) dedicated to mature asset in Gabon that took place in 2008. Particular focus is given to the assessment of how initial objectives in terms of functionality and practical benefits - namely daily diagnosis, setting and asset-wide optimization - have been fulfilled. The last part details how the lessons learned during this period allowed Total Gabon to extend in an efficient way the WPM solution to another mature oilfield of its portfolio, as part of a major rejuvenation and additional development programme.
The proposed material is of direct application for whoever is to develop, deploy or use a real time monitoring solution involving one or several of the following features: multiple databases, multi-disciplinary teams, workflow oriented approach, modelling and optimisation, shared application. It is of particular use to anyone involved in mature asset production optimization. Several key success drivers are highlighted and illustrated through detailed examples: –Identify and involve key users–Promote early operational feedback–Audit instrumentation, communication, network, databases, applications and models–Identify and prepare necessary adjustments of business processes–Avoid project overselling–Provide impeccable and proactive user support–Initiate and maintain momentum
This paper provides an un-biased feedback from the end-user point of view based on three years of extensive use and testing in real operations. Moreover, technical and organizational issues faced during the early deployment phase are thoroughly discussed, focusing on the importance of change management. Finally, the paper describes how it has been possible to capitalize upon the initial experience in order to improve the efficiency of the deployment of the WPM solution on a second asset.
Predicting Wellbore Dynamic-Shock Loads Prior to Perforating
Authors: Burman Jack , Schoener-Scott Martin , Le Cam , Suire David 
Published: September 2011

Abstract
Oilwell casing perforating has been used in the industry since 1932 and was pioneered by the Lane-Wells Company who introduced the bullet-gun perforating technique. Shortly after the introduction of the bullet gun, explosive jet perforators were introduced, which provided a different and more aggressive way to perforate casing.
With the increased demand for oil and gas over the past decades, operators have been forced to explore deeper, hotter reservoirs to find the most prolific reservoirs. These deepwater opportunities have required constant changes to equipment and services to increase their technical capabilities for performing in more critical environments. Perforating with higher-shot densities, propellants, and larger perforating guns has been ongoing to meet these new challenges.
A major problem with these increases, however, is the difficulty in predicting dynamic wellbore behaviors that cause tubulars to collapse and bend and packers to unset as perforating guns were detonated. Research to understand the pressure behavior during the perforation event, in addition to the solid loading that is imparted to the tubulars, packers, and other completion hardware in the perforating assembly, was needed to enable the industry to go forward with a high level of confidence that wells could be completed safely and cost effectively.
This paper discusses a shock-wave computer modeling program that evaluates the mechanical risk factors of well components to ensure that the health, safety, environment, and service quality needs in a design are addressed. A time-marching, finite-differences technique is applied as the numerical method for both fluids and solids. The software is installed on a personal computer and typically executes the models within several minutes to several hours, depending on the complexity of the job design.
The physics-based model has been validated (Schatz et al. 1999; Schatz et al. 2004) with special high-speed recorders that sense pressure, temperature, and acceleration at a sampling frequency of 115,000 samples per second.
This paper provides data from offshore oil and gas wells in the Gulf of Mexico to demonstrate the success of the design.
A Practical Guide to Interpreting Microseismic Measurements
Authors: Cipolla C. , Maxwell S. , Mack M. , Downie R. 
Published: September 2011

Abstract
Thousands of hydraulic fracture treatments have been monitored in the past ten years using microseismic mapping, providing a wealth of measurements that show a surprising degree of diversity in event patterns. Interpreting the microseismic data to determine the geometry and complexity of hydraulic fractures continues to be focused on visualization of the event patterns and qualitative estimates of the "stimulated volume", which has led to wide variations and inconsistencies in interpretations. Comparing the energy input during a hydraulic fracture treatment and resultant energy released by microseismic events demonstrates that the seismic deformation is a very small portion of the total deformation. The vast majority of the energy is consumed in aseismic deformation (tensile opening) and fluid friction (Maxwell et al. 2008). Proper interpretation of microseismic measurements should account for both seismic and aseismic deformation, coupling the geomechanics of fracture opening and propagation with the shear failures that generate microseisms.
Interpretation of microseismic measurements begins with an evaluation of location uncertainty, using signal-to-noise ratios and error ellipsoids, along with event moment magnitude. In some cases, microseismic event location uncertainty is erroneously interpreted as fracture complexity. The next step is to normalize the data and correct for observation well bias, both distance and azimuth, including use of seismic radiation patterns. Without these corrections fracture behavior from well to well or stage to stage (especially in horizontal wells) can easily be misinterpreted. Advanced geophysical processing that describes the failure mechanisms in more detail may also aid in the interpretation. The final step in the interpretation is to include the geomechanics of the overall process, accounting for the fracture treatment volumes injected, the net pressure in the hydraulic fracture(s) and the shear failures that generated the microseisms. This final, critical step is often overlooked when interpreting microseismic measurements. The paper provides a comprehensive, yet practical guide to the interpretation of microseismic measurements.
Understanding Hydraulic Fracture Variability through Integrating Microseismicity and Seismic Reservoir Characterization
Authors: Maxwell S. C. , Pope T. , Cipolla C. , Mack M. , Trimbitasu L. , Norton M. , Leonard J. 
Published: September 2011

Abstract
Microseismic measurements were integrated with seismic reservoir characterization and injection data to investigate variability in the hydraulic fracture response between three horizontal wells in the Montney shale in NE British Columbia, Canada. When wells were close enough, hydraulic fractures were found to interact with pre-existing faults, which acted as a barrier to fracture growth, and resulted in relatively large-magnitude microseismicity. The increased level of microseismic deformation and corresponding fault-related source characteristics correlated with the presence of a pre-existing fault identified by edge detection/ant tracking algorithms applied to seismic reflection data. In cases where the wells were far from pre-existing faults simple, planar hydraulic fractures were observed, although there was a tendency to grow towards regions of low Poisson's ratio based on amplitude versus offset inversion of the seismic reflection data. The tendency for the hydraulic fractures to be asymmetric and grow preferentially towards the low Poisson's ratio region is attributed to material property changes and associated lower stresses in these regions. Integrating microseismic interpretations and fracture treatment data with enhanced reservoir characterization has been used to rethink well placement and completion designs, resulting in improved well performance.
Improved Basin Analog Approach to Characterizing Frontier Basins for Unconventional Gas Resource Potential
Authors: Cheng Kun , Wu Wenyan , Holditch S. A. , Ayers W. B. , McVay D. A. 
Published: September 2011

Abstract
During the past decades, investigation of unconventional gas resources has become a significant area due to its promising outlook of meeting the future energy needs. When the unconventional gas resources, especially those in frontier basins, expose a set of challenging issues that both knowledge and practice are very limited, basin analog analysis has been employed for preliminary assessments of frontier plays.
For basin analog, it compares a comprehensive spectrum of features between the target basin and reference basin, and this process involves large-volume data with broad value ranges. To rapidly and effectively evaluating the unconventional hydrocarbon resource potential in frontier basins (i.e., the target basins), basin analog approach has been proposed since 2008, in combination with a database populated with well-characterized geologic and petroleum systems information of North America basins that have significant unconventional resource development (i.e., the reference basins). The continuing investigation has been based on the public literature, and it is noted that data of many petroleum systems are incomplete that cannot cover the entire comprehensive parameters. This problem is inherently typical of the unconventional basins: many unconventional petroleum systems are newly developed and the characterization data are unavailable; or the unconventional basins, especially for the frontier basins, are exploratory with many plays undeveloped or in the very early development stage. Another major problem in analyzing basin analog is that parameters are usually multi-valued due to the wide range of petroleum systems.
In this paper, we analyzed the previous approaches of basin analog analysis and proposed an improved solution to the problems. The improved method is based on extracting the characterized parameter distributions in basin scale, and compares distributions by using probability theory and information theory. This method can not only solve the incomplete analog and multi-value comparison problems to achieve more accurate results, but also directly reflect the quantified distributions of different parameters in multiple basins simultaneously. Also discussed are validation of the analogous relationships by basin resource distributions and the further usage of the improved basin analog analysis for estimating unconventional resource volumes in frontier basins.
Shale Permeability Determined by Simultaneous Analysis of Multiple Pressure-Pulse Measurements Obtained under Different Conditions
Authors: Civan Faruk , Rai Chandra S. , Sondergeld Carl H. 
Published: September 2011

Abstract
Several pressure-pulse measurements are conducted on similar plugs extracted from various tight-shale formations under different boundary conditions. A theoretically rigorous model-assisted analysis of a number of data sets is carried out for achieving uniqueness in determination of intrinsic shale permeability. The best estimate values of the unknown parameters, including the Langmuir volume and pressure, and the intrinsic permeability of the shale samples at a reference condition are determined by matching the numerical solution of our improved non-Darcy model simultaneously to several sets of the observed pressure-pulse transmission data. Simultaneously, we delineate the dominant characteristics of the apparent permeability and the contribution of the various flow regimes. It is concluded that our improved method provides a better match to the pressure-pulse decay tests than the previous models which assumed Darcy flow. Further, our formulation allows for model-assisted extrapolation to other conditions once the unknown parameter values have been estimated under laboratory testing conditions.
Palynofacies Analysis and Submicron Pore Modeling of Shale-Gas Plays
Authors: Elgmati Malek , Zobaa Mohamed , Zhang Hao , Bai Baojun , Oboh-Ikuenobe Francisca 
Published: September 2011

Abstract
The present study combines palynological applications with advanced microscopic techniques to characterize the Utica, Haynesville and Fayetteville shale-gas source rocks. This unprecedented approach could offer an alternative way to measure the total organic carbon (TOC) content using the 2D subsurface Scanning Electron Microscope (SEM) images. This approach is considered to be a faster and inexpensive method compared to conventional geochemical analyses. Palynofacies analysis provided valuable information about kerogen type and its degree of thermal maturation, which are key parameters in shale-gas exploration. Moreover, it qualitatively allowed the estimation of important organic geochemical parameters such as vitrinite reflectance (Ro %) and numerical thermal alteration index (TAI). New high resolution microscopic solutions have successfully been exploited for source rock characterization at both micro- and nano-meter scales. In-situ Focused Ion Beam (FIB) and Scanning Electron Microscope (SEM) technologies provided new insights into rock fabrics such as porosity, permeability, tortuosity, anisotropy and kerogen content. Serial sectioning and sequential imaging using dual beam SEM/FIB instrument were implemented successfully to characterize the 2D kerogen content and 3D submicron-pore structures. Moreover, pores were found in organic matters with the size of nano level and occupy 40–50% of the kerogen body. A successful example of reconstructed 3D pore model from Fayetteville Shale is presented.