bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hands-on Teaching for Petroleum Engineers in the 21st Century: a Balance between High-Tech and Simple Demonstrators
Authors: Teodoriu Catalin 
Published: October 2012

Abstract
Teaching petroleum engineers requires a balance between mathematics and engineering or in other words between abstract concepts and the real world. Several scientists have shown that visual aids help students to learn better and to retain the knowledge. Furthermore, students pay more attention to gadgets and high-tech systems because they were born in this contemporary era. Teaching using multimedia has become standard practice, but students tend to lose the link to reality.
Several years ago, a new concept of teaching undergraduate and graduate students was introduced at Clausthal University of Technology, based on the implementation of hands-on teaching systems that not only expose the students to physical models, but also require them to build such models or to generate experiments using existing models.
The results from the 3-year experience at Clausthal University of Technology show an improved learning capability of the students, in combination with better knowledge transfer efficiency between teacher and students. This paper presents the results of students’ competitions held at Clausthal University of Technology as part of their studies. For example, a comparison is made between the outcomes of groups that chose to work on high-tech multimedia tasks versus those students who built more conventional tools (e.g. a surge and swab simulator, a hoisting system model and a laminar flow rig).
Finally, the students’ feedback concerning the hands-on teaching concept will be summarized in this paper.
New Generation Magnetic Resonance While Drilling
Authors: Heaton Nicholas , Jain Vikas , Boling Brian , Oliver David , Degrange Jean-Marie , Ferraris Paolo , Hupp Douglas , Prabawa Hendrayadi , Torres Ribeiro Mauro , Vervest Edwin , Stockden Ian 
Published: October 2012

Abstract
In this paper, a new series of Logging-while-drilling (LWD) nuclear magnetic resonance (NMR) tools is introduced. The tools incorporate a magnet arrangement which provides a low field gradient minimizing adverse lateral motion effects. T2 distributions are measured while drilling or sliding in a range
of hole sizes, including large holes previously inaccessible to LWD NMR measurements. Benefits and trade-offs of key tool design features are presented. Emphasis is placed on measurement quality, operational simplicity and log quality control in real time and memory mode through example logs from operator wells. Real-time T2 distributions provided by the new generation LWD NMR tool enable a full range of NMR answers, including lithology-independent total porosity, bound fluid volume and permeability. Real-time log quality controls monitor tool noise, antenna sensitivity, tuning quality and lateral motion. Acquisition sequences are optimized for porosity precision and accuracy in different environments. Drilling data have been acquired in several operator wells and a test well covering diverse ranges of formations and logging conditions. Environmental factors affecting porosity precision and T2 quality are discussed with reference to log quality indicators and comparison with wireline NMR logs is made where available. In general, the LWD tools deliver NMR answers comparable to the analogous wireline logs in terms of precision, accuracy and vertical resolution. With increased industry focus on LWD services and heightened sensitivity to downhole chemical sources, the need for reliable LWD NMR measurements continues to grow. In addition to a sourceless porosity measurement, NMR provides unique quantitative information on the disposition of producible fluids, which is not available from other logs. Real-time producibility information can be used to optimize formation pressure measurements and sampling as well as for timely completions and well placement decisions. The new generation LWD NMR tools introduced here addresses this need.
A Superior, High-performance Enzyme for Breaking Borate Cross-linked Fracturing Fluids under Extreme Well Conditions
Authors: Zhang Bin , Huston Adrienne , Whipple Lawrence , Urbina Hugo , Barrett Ken , Wall Mark , Hutchins Rick , Mirakyan Andrey 
Published: October 2012

Abstract
Enzyme breakers have been previously used for hydrolyzing guar gels at temperatures below 150°F. There is an industry-wide demand for enzyme breakers that can function under higher temperature (200-250°F) and extreme pH (≥10.5) conditions. To fill this gap, Verenium Corporation has developed an exceptionally thermo-stable cellulase enzyme, referred to hereafter as mannanase, that was discovered from a hydrothermal vent sample. This mannanase exhibits well differentiated performance under extreme downhole conditions encountered in gas shales and deeper oil/gas wells.
This superior mannanase can effectively break linear and borate cross-linked guar under broad ranges of temperature (80°F up to at least 225°F as seen by rheology and up to 275°F using residual activity analysis ) and pH (3.0 up to 10.5). The results of rheological tests show that only a small dose is required (100 ppm or less) to achieve the complete break. The enzymatic reaction can be triggered by the changes of temperature and pH during fracturing operations. This mannanase also exhibits a dose response that allows the operator to generate a desirable viscosity/time profile by adjusting enzyme dosage. Even in the presence of fluid additives, such as buffers, salts, stabilizers and cross-linkers, this mannanase is active for effective viscosity reduction.
This mannanase breaker belongs to the glucanase family. It reduces gel viscosity by specifically targeting β -1,4 glycosidic bonds between the mannose units in guar. The carbohydrate profiling tests demonstrate that this enzyme effectively and efficiently breaks the long-guar polymers into small, soluble fragments that will eliminate gel re-healing. The conductivity tests demonstrate extensive cleaving of guar and removal of polymer residues that cause formation damage and reduce fracture conductivity.
One Year of Just-In-Time Perforating as Multi-Stage Fracturing Technique for Horizontal Wells
Authors: Angeles Renzo , Tolman Randy , Gupta Jugal , Benish Tim , Ross Kirk , Cole Stephen , Garner Christopher , Lopez Thomas 
Published: October 2012

Abstract
In order to reduce stimulation costs, most conventional methods incorporate hydraulic fracturing of multiple perf clusters over multiple stages to treat large segments of shale rock in horizontally completed laterals. Under ideal situations, this technique would create equally-stimulated fractures at each perf cluster. However, in practice, such treatments can create overstimulation in some perf clusters and under-stimulation in others with unknown stimulated lengths and volumes. As operators move towards increased number of stages, increasingly larger number of plugs cause additional wireline trips and associated plug drilling time, which increases the total cost and mechanical risk of the completion. In some fields, operators use combinations of ball actuated sleeves and plug-and-perf methods due to technical limitations in drilling out of all the frac plugs. In response to these practical issues, ExxonMobil has implemented its proprietary Just-In-Time Perforating (JITP) technique in multiple horizontal wells over the last year. Prior to this deployment effort, JITP had been extensively used in vertical and S-shaped wells in the Piceance basin, Colorado.
This paper discusses the learnings obtained after one year of multi-stage fracturing using horizontal JITP in unconventional plays. JITP creates multiple single-zone fracture stimulations on a single wireline run using ball-sealer diversion and perforating guns that remain downhole during fracturing. With the unique granularity of single-zone fracturing, much has been learned about the shale and treatment design. Better placement control can be useful in avoiding fracturing into offset wellbores. Field applications have confirmed the use of less horsepower, fewer frac plugs, improved fracture placement control, and added flexibility in water management. This paper also reviews technical considerations for other completion designs and fluid systems as well as opportunities for enhanced operations based on recent field learnings.
First Intelligent Well Completion in the Troll Field Enables Feed-Through Zonal Isolation: A Case History
Authors: Dahle Bjørn Olav , Smith Peter E. , Gjelstad Geir , Solhaug Kristian 
Published: October 2012

Abstract
Statoil operates the Troll Field in the Norwegian Sector of the North Sea and wished to run a deep sidetrack from the mother bore in a multilateral well that would exit through the 10-3/4-in. liner in the reservoir. The plan would have to address several new challenges, including an intelligent completion that would offer zonal isolation for four zones and dual pressure and temperature for all oil zones; these were not usual requirements for the standard multilateral wells in the field.
Statoil had evaluated several zonal-isolation methods, and based on previous experience, they decided to use swellable packer technology. Since this would be the first intelligent-well completion in Troll field and the first ever for Statoil using feed-through swellable packers, a full scale test to qualify the technology was required. Swelling and differential-pressure tests were initiated using oil from the Troll field. Testing revealed that this type of completion actually would exceed the necessary requirements.
The lower completion was designed with 7-in. inflow-control-device (ICD) mesh screens and three openhole swellable packers to isolate the reservoir into three separate oil zones and to separate the gas cap. The inner completion string was designed with three dual gauges, three 3-1/2-in. feed-through swellable packers, three 3-1/2-in. hydraulic flow-control valves, and a hydraulically operated gas-lift valve below the production packer to allow natural gas lift.
The installation was performed from a semi-submersible rig without an HSE incident and ahead of plan. The well was put on production shortly thereafter, and zonal isolation was confirmed by selective closure of the flow-control valves. The paper will discuss the swellable packer design, qualification testing, planning, installation, and the results of this intelligent completion, which was the first in the Troll Field.
Information from a Downhole Dynamics Tool Provides Real-Time Answers for Optimization While Drilling 10,000 ft Laterals in the Middle Bakken Formation of the Williston Basin
Authors: Chrisman John , Orley Cole , Hood James , Stone Casey , Fleischhacker Curtis , Leopold Nathan , Taylor Richard 
Published: October 2012

Abstract
Economically exploiting the Bakken reservoir of the Williston Basin requires long horizontal wellbores through the drilling zones which continually change from sandstone to siltstone to shale with hard calcite cementation. Changes of formation within the drilling zone have caused numerous drilling challenges by creating dynamics issues, resulting in vibration problems and bit/bottom hole assembly deflections. These, in turn, result in high local doglegs that lead to a loss of drilling efficiency.
Traditionally, a real-time downhole dynamics tool has been used occasionally within lower-cost drilling projects to accelerate learning about the downhole environment. This knowledge and real-time control of drilling parameters are essential. However, the value of these downhole tools may be underexploited, since they might not be considered economical for everyday use in the lower-cost drilling projects. Case history examples display the benefits due to the closer-to-the-bit steering control from bending moment and bending toolface data, and have made the use of this downhole dynamics tool a necessary choice.
This paper will expand on the challenges encountered while drilling the long lateral sections in the Williston Basin, and show how the use of real-time downhole dynamics information helped optimize the drilling effort by saving time and increasing the percentage of successful one-run laterals. Furthermore, the paper expands on the practical use of the directional information from bending moment and bending toolface close to the bit thus allowing the directional driller to make better real-time decisions on whether a wellbore correction is really needed. The paper is supported with over 30 months of field examples and results.
Kuparuk River Unit Field - The First 30 Years
Authors: Jensen Trond B , Little Laird , Melvin John , Reinbold Eric , Jamieson David , Shi Wen 
Published: October 2012

Abstract
This paper will review the history and current operations of the Kuparuk River Unit (KRU) field, the second largest field on the North Slope and one of the largest fields in the US. The field is a legacy asset in the ConocoPhillips portfolio with more than 6 BBO OOIP. The field came on line in December 1981 and has produced 2.25 BBO to date through water flood, immiscible water-alternating gas (IWAG) and miscible water-alternating-gas (MWAG) injections. Currently the field produces 90,000 bopd, 460,000 bwpd and 210 MMscf/d gas, and injects 570,000 bwpd and 160 MMscf/d miscible injectant.
Some of the recent challenges at KRU include: maintaining pressure support (water injection) through an aging infrastructure, development and use of fit-for-purpose simulation models to support field management decisions, estimation of facilities back-out from a complex multi-field system, and optimization of one of the largest MWAG EOR floods in the world. History and current status of the KRU field will be discussed.
Azimuthally Focused LWD Sonic Logging for Shear Wave Anisotropy Measurement and Borehole Imaging
Authors: Mickael Medhat , Barnett Craig , Diab Mohamed 
Published: October 2012

Abstract
An azimuthally focused LWD sonic tool has been developed to resolve shear wave anisotropy in fast formations, and provide borehole images of compressional and shear acoustic slowness. As the drillstring rotates, waveform measurements are recorded in 16 fixed-orientation azimuthal bins. The waveforms are processed to yield azimuthally oriented compressional and refracted shear slowness values.
Most shale reservoirs exhibit significant intrinsic anisotropy. Knowledge of the acoustic velocities and anisotropy ratio is vital for properly computing formation mechanical properties and modeling hydraulic fracturing performance, as well as for seismic processing and interpretation. Yet VTI shear wave anisotropy cannot be resolved from dipole measurements in vertical wells, and such data are rarely available from horizontal wellbores.
The LWD azimuthal sonic sensor has been successfully tested in horizontal shale reservoir wells in the northeastern U.S., where VTI shear wave anisotropy of 5 to 50 percent was clearly measured in the horizontal sections. Borehole images constructed from azimuthal shear slowness data provided a clear visual indication of the orientation and magnitude of the shear wave anisotropy, while compressional slowness borehole images compared well with conventional images from LWD azimuthal gamma ray and density tools, and can provide information on formation dip and the stratigraphic position of the horizontal wellbore.
Azimuthally focused LWD sonic measurements of compressional and anisotropic shear wave slowness provide new and valuable information from horizontal shale wells, supplying geomechanical data necessary for more informed hydraulic stimulation programs, as well as providing geophysicists with key anisotropy parameters and complementing data available from vertical wells to provide a complete three-dimensional compressional and shear velocity model.
Parameters Controlling Hydraulic Fracturing and Fracture Tip-Dominated Leakoff in Unconsolidated Sands
Authors: Hurt Robert S. , Germanovich Leonid N. 
Published: October 2012

Abstract
Hydraulic fracturing of unconsolidated materials has been a long-recognized technique to control sand production. This work describes the results of an experimental investigation on the dominant parameters of hydraulic fracturing in unconsolidated sands. The variables in this study, each varied by several orders of magnitude, are sample permeability, fluid rheology, remote stresses, and fluid injection rate. We have quantified the results of these experiments in terms of injection pressuretime history, fracture aperture, and leakoff thickness. Directly measuring the magnitude of fracture aperture and leakoff thickness is significant in hydraulic fracturing of unconsolidated materials to constrain modeling this process.
Laboratory observations presented here suggest that in our experiments, the leakoff process is primarily confined to the tip of the fracture and that leakoff precedes fracture propagation. This may be the first direct experimental observation of the dominance of the leakoff process in the tip region of a propagating fracture in cohesionless materials.
Our experimental results also suggest that the primary factor affecting peak (initiation) pressure and fracture aperture is the magnitude of the confining stresses. However, the morphology of the fracture (and fluid leakoff zone) changes significantly not only with stresses, but also with other parameters such as flow rate, fluid rheology, and sample permeability. Typical features of the observed fractures are multiple offshoots, a blunt fracture tip, leakoff primarily confined to the fracture tip region, and material shear banding. Dimensional analysis of the recorded experimental data results in the power-law dependence of the peak injection pressures on the dominant experimental parameters.
The results presented here quantify the effect of the experimental parameters on injection pressures, magnitude of leakoff, and fracture aperture. This is a significant development and our data set is consistent with available field observations, also discussed in this work.
The Braess Paradox and its Impact on Natural Gas Network Performance
Authors: Ayala H. , Luis F. , Blumsack Seth 
Published: October 2012

Abstract
Steady increases in natural gas transportation volumes have prompted operators to reevaluate the performance of the existing gas pipeline infrastructure. In order to accomplish an increased transportation capacity, conventional wisdom dictates that adding an additional link or a pipe leg in a gas transportation network should enhance its ability to transport gas. Several decades ago, however, Dietrich Braess challenged this traditional understanding for traffic networks. Braess demonstrated that adding extra capacity could actually lead to reduced network efficiency, congestion, and increased travel times for all drivers in the network (the so-called "Braess Paradox"). The study of such counter-intuitive effects, and the quantification of their impact, becomes a significant priority when a comprehensive optimization of the transportation capacity of operating gas network infrastructures is undertaken. Corroborating the existence of paradoxical effects in gas networks could lead to a significant shift in how network capacity enhancements are approached—challenging the conventional view that improving network performance is a matter of increasing network capacity. In this study, we examine the occurrence of Braess’ Paradox in natural gas transportation networks, its impact and potential consequences. We show that paradoxical effects do exist in natural gas transportation networks and derive conditions where it can be expected. We discuss scenarios that can mask the effect and provide analytical developments that may guide the identification of paradoxical effects in larger scale networks.
Shale Gas Hydraulic Flow Unit Identification Based on SEM-FIB Tomography
Authors: Zhang Hao , Bai Baojun , Song Kai , Elgmati Malek 
Published: October 2012

Abstract
Shale gas reservoir developments have steadily increased over the past few years throughout North America. A significant amount of the produced gas in shales is stored in complex submicron pore structures. The absence of an intensive hydraulic flow unit (HFU) model for these shale gas source rocks makes the prediction of economic gas productivity and hydraulic fracturing risky. Therefore, understanding of pore size distribution, permeability, pore connectivity, and other petrophysical properties is crucial for accurate performance prediction and effective reservoir management. This study utilizes the dualbeam (SEM-FIB) instrument for shale gas tomography. The reconstructed 3D sub-micron pore model provides insights into the petrophysical properties of shale gas, including pore size distribution and porosity. These properties were used to define the shale gas hydraulic unit and permeability. The identified flow units were able to fit into existing flow unit models for unconventional reservoirs. The comparison between the proposed method and mercury injection capillary measurements (MICP) revealed similar data range however MICP method tends to slightly overestimate the flow unit. Flow simulation based on 3D Stokes equation using image segmentation was performed and consistent permeability value was found compared to the estimation in SEM-FIB tomography. However, the permeability simulation results tend to underestimate the permeability value in reality. A case example from Utica shale illustrated the use of this approach.
Production Decline Analysis of Horizontal Wells Intersecting Multiple Transverse Vertical Hydraulic Fractures in Low-Permeability Shale Reservoirs
Authors: Poe Jr Bobby D. , Vacca Herman , Benjamin Art , Atwood W. Keith 
Published: October 2012

Abstract
This paper reports the development and application of production performance decline analysis techniques that are applicable for the characterization of the well and reservoir properties of low permeability fractured shale gas or oil reservoirs which are completed with horizontal wells intersected by multiple, transverse, finite-conductivity, vertical fractures. This type of well completion is now the most common type of completion technique that is currently being used to develop wells in low permeability fractured shale gas and oil reservoirs in North America.
It can be extremely difficult, if not technically impossible, to fully characterize the physical properties of unconventional reservoirs using conventional transient testing methods within a reasonable amount of time or at an acceptable cost. Instead, the production performance of these wells can be evaluated using transient production decline analysis techniques to determine the reservoir properties [permeability and estimated Stimulated Reservoir Volume (SRV)] and the well completion effectiveness [effective fracture half-length and conductivity] of the system.
The production decline analyses that have been developed in this work include both graphical production decline diagnostic analyses and history matching with a multiple-transverse fracture horizontal well transient solution using regression analysis techniques. Specialized diagnostic analyses have been developed for the intermediate flow regimes that are commonly exhibited in the transient performance of multiply-fractured horizontal wells to obtain estimates of or limits on the reservoir and well properties, which are then refined using nonlinear minimization techniques in a history matching analysis.
A field case history example is presented in this paper to demonstrate the application of the production performance analysis procedures. The evaluation of the reservoir properties and well completion effectiveness of multiply-fractured horizontal wells in fractured shale reservoirs using the transient production performance of these wells is of tremendous importance to the petroleum industry. It has been found that a combined production diagnostic - history matching analysis provides a reliable and accurate means of properly characterizing the properties and production performance of multiple-transverse- fractured horizontal wells in low permeability shale reservoirs.