bluuebunny/crossref_metadata_2025_split huggingface dataset:
Offshore Project Risk Management Model (OPRMM) As a Tool for Efficient Field Development
Authors: Talipova Aminam 
Published: September 2015

Abstract
Risk Management approach is an essential part of the project. Large industries and particular companies incorporate RM Culture. Statistics shows, that companies with Project Management (PM) Structure reduce cost ineffectiveness up to 20%. In oil and gas industry PM Risk Analysis (PRMA) has been widely used for the last years. Various models and procedures have been developed to manage projects of different scale.
Nonetheless, Offshore Projects (OP) complexity, high uncertainty of technical, financial, market and government factors, as well as different sea conditions, still makes sense to improve general PRMA models according to the oil and gas OP features. Traditional RM tools and techniques are not appropriate to cope with complex projects in the Arctic. Companies will have to modify risk assessment process or look for new methods. The paper suggests OPRMM, where the attempt to implement PM tools and techniques together with mathematical modeling and expert assessment is made and institutional factors are included. Practically, it is founded on the comparison between offshore field development in the Barents Sea and the Kara Sea. The reason for research is debates around future Arctic oil and gas projects and their commercial potential. Several large projects with participation of major international companies in the Barents Sea and the prospectivity of the Kara Sea Projects in conditions of technology difficulties are under discussion and have not reached the investment project phase yet. OPRMM starts with identifying the key factors, which could affect offshore field development. Inside the investment regime modified real option value (ROV) model for OP is developed: stop option and scale transformation option. Basing on the binominal trees and Monte Carlo Simulation it is possible to see the perspectives of the OP at an early stage in the conditions of high uncertainty. Incorporating the ROV model into investment regime allows operator to choose the territory to explore.
The research shows, that offshore projects in the Arctic offshore is not only under the pressure of internal corporative factors, but also under influence of external institutional factors. New tools and approaches will be required in Arctic projects where no one wants to be looking in the wrong place.
Use of Novel Self-Healing Materials to Control Sustained Casing Pressure and Prevent Long Term Environmental Impact
Authors: Arif Khattak Mohammad , Jain Bipin , Al Kalbani Sultan , Ahmed Junaid , Arya Afrianto Agung , Qassabi Nabhan , Aghbari Salim , Salti Anwar , Rashdi Sami 
Published: September 2015

Abstract
PDO is the biggest Oil and Gas Producer in Oman drilling in several fields with a number of drilling and cementing challenges. One of the key challenges that the operator has started to encounter is sustained casing pressure (SCP) because of poor zonal isolation. Hydrocarbons are observed in B or C annuli and lab analysis confirms it is coming from one of the Limestone reservoirs. More than 4 wells that were drilled in 2012 and 2013 have been identified with SCP and others are being monitored. The drilling campaign in this particular field was halted because of SCP problems and failure to comply with government regulations. Expensive work-over operation had to be done to abandon the wells.
Owing to the fact that conventional cement systems and practices have proven ineffective, an innovative self-healing cement system was introduced. This system has the property of self-repair when in contact with hydrocarbons, seals any pathways and restores well integrity without any intervention thus providing long term zonal isolation. The system is placed conventionally in the annulus as part of the cement slurry and the healing material stays dormant till the time it sees the hydrocarbons that may flow through the cracks. Subsequently it expands and heals the cracks.
The self-healing cement system has been tried in four wells in the same field with excellent results. After more than one year of completion, no gas pressure has been observed in the annulus. The operator has standardized this system for this field for all future wells and plans to extend the use to other fields with similar issues.
This paper will cover details on the system, mechanism of work, validation process of the system, operational aspects and field implementation to elaborate how SCP problems can be overcome.
Intelligent Use of Big Data for Heavy Oil Reservoir Management
Authors: Popa Andrei S. , Grijalva Eli , Cassidy Steve , Medel Juan , Cover Andrew 
Published: September 2015

Abstract
In recent years, the application of Big Data technologies and associated analytics has enjoyed significant attention and has seen an enormous growth in the oil industry. This is due to exponential growth of both historical and real-time data being collected. In this article, we present examples of the successful application of these technologies for the management and optimization of large heavy oil reservoirs. These particular reservoirs present a very interesting, yet complex, challenge given the steam assisted gravity drainage recovery mechanism and the thousands of producers, injectors, and observation wells which generate terabytes of data on a daily basis. To handle all this large and high-dimensional information efficiently, we introduced new workflows consisting of operational domain data acquisition, data transfer to business domain, storage in accessible repositories, and ending with data consumption, quality control, visualization and analytics.
The paper summarizes how big data is aggregated into smart applications to monitor the reservoirs and observe steamflood recovery development. Examples of high definition DTS data integrated with completion, wellbore equipment, geologic markers, and real-time wellhead pressure showing reservoir heating and/or cooling are presented. Intelligent visualization tools and analytics, such as pattern recognition applied on static and dynamic subsurface data enabled superior heat management. A second example of high efficiency operations enabled by big data is the well integrity during cyclic steam operations. Pressure and injection rate data streams are integrated with analytics to monitor and identify abnormal operating conditions. Lastly, an example of facility reliability and production impact quantification is demonstrated through use of integration of surface system stream data and subsurface well information. The later led to significant business impact in terms of realized production and operation cost savings.
The examples presented in this paper demonstrate the business impact and value creation generated by efficient use of the Big Data technologies and associated analytics for heavy oil reservoir management and optimization. The workflows are now used in all Chevron heavy oil fields in San Joaquin Valley.
Non-intrusive Multiple Zone Distributed Acoustic Sensor Flow Metering
Authors: Finfer D. , Parker T. R. , Mahue V. , Amir M. , Farhadiroushan M. , Shatalin S. 
Published: September 2015

Abstract
The Distributed Acoustic Sensor (DAS) used here (Parker et al., 2012), allows both the amplitude and the phase of acoustic signals to be continuously recorded along a length of optical fiber. In this paper, non-intrusive flow metering based on the use of this sensor is performed for different pipe sizes and flow conditions. By wrapping a continuous length of fiber helically around the exterior pipe, the system measures the dynamic radial strain (hoop strain) along a pipe with a spatial resolution on the order of millimeters and a time resolution on the order of tenths of milliseconds. As a result, this implementation of the sensing system output makes it possible to visualize the generation and convection of eddies by using a waterfall plot of distance versus time. By analyzing the recorded data using a frequency-space transformation (f-k plot), it is possible to determine precisely both the speed of eddies, as well as the speed of sound.
This paper will present experimental results from single- and multi-phase tests to demonstrate the applicability of the technology to the monitoring of fluid velocity and the determination of flow composition. It will be seen that the system, which can be installed unobtrusively, is straightforward to apply for several types of commonly encountered flow regimes. Further, this paper will also consider several practical aspects regarding the installation and use of such a system in the oilfield. Finally, it will be shown how multiple monitoring zones can be incorporated using a single optical fiber. It will be seen that this system is non-intrusive and can be retrofitted to existing pipes to monitor the flow simultaneously at multiple locations for accurate flow profiling and characterization.
High-Performance Plug-and-Perf Completions in Unconventional Wells
Authors: McNelis Liam , Salt Warren , Scharf Thilo S. 
Published: September 2015

Abstract
An innovative new design of a perforating system for plug-and-perf completions in unconventional wells demonstrates that operations can be made more efficient, safe and reliable. Results from extensive modeling, testing and field tests demonstrate that the entire perforating process, including gun loading, arming, running, perforating, maintenance and disposal, is made more robust by eliminating traditional approaches to selective perforating, detonators, gun hardware and accessory equipment.
The new system optimizes perforating operations with fully assembled and ready-to-shoot gun modules delivered to the base or to the wellsite. An innovative integrated switch-detonator design replaces all wiring and crimping to eliminate human error and to significantly reduce the risk of inadvertent ignition or detonation. Arming a gun is now as efficient, safe and reliable as placing a battery in a flashlight. True intrinsically safe microprocessor switch-detonators require no wiring so they achieve measurably higher reliability than standard separate switch-detonator combinations, and they are immune to potential hazards that can impact standard selective perforating equipment in use today. Surface test equipment detects any malfunctions before running in hole, and the software allows continuous monitoring of all downhole components until initiation and in between shots. All wellsite operations can continue without interruption, and full selectivity, communication to all detonators, stage-skipping and gun redundancy are enabled for the most complex completions. Gun length, shot phasing, shot density and charge type are fully customizable with injection-molded gun parts that do not create unwanted debris after perforation.
The system design targets a 10X improvement in reliability over existing plug-and-perf equipment. Wireline service companies traditionally experience reliability in unconventional well perforating ranging from 30 runs/misrun to 100 runs/misrun. Early results suggest the new system may exceed 1,000 runs/misrun. By reducing the risk of mishaps, misruns and misfires, rig time is saved, frack costs are lowered, and every stage can be perforated to contribute to higher well productivity.
Field tests of the new design demonstrate the advantages of a fully integrated perforating gun system. The new technology leverages innovative component-level features and a system design approach to produce a perforating system that eliminates many of the causes for misruns, increases simplicity and safety of operations, and delivers higher well productivity.
Differentiating Open Natural Fractures From Healed Fractures Using The New, High-Definition Oil-Based Mud Microelectrical Imager – Case Studies From Organic Rich Shales
Authors: Li Bingjian , Chen Yong-Hua , Gawankar Kiran , Miller Camron K. , Xu Weixin , Laronga Rob J. , Omeragic Dzevat 
Published: September 2015

Abstract
Distinguishing open natural fractures from healed fractures has been a significant challenge in shale formations drilled with oil-based mud. Ultrasonic imaging tools can locate open fractures, but such data is seldom acquired due to concerns related to the effects of heavy mud and, in high-angle wells, operational efficiency and tool eccentralization. Until now, the microelectrical image tools in the market were not capable of differentiating open fractures from healed fractures in oil-based mud.
A new, high-definition oil-based mud microelectrical imager has been deployed that operates at high frequencies and provides images with high borehole coverage. This new tool can identify natural fractures, sub-seismic faults, and other geological features in the reservoirs. In addition to high-resolution images of formation resistivity, an advanced inversion processing can be applied to generate resolution-matched images of the quantified standoff between each sensor in the array and the borehole wall. Such standoff images are of special value for differentiating open fractures from healed fractures. The use of these standoff images are presented in several recent case studies from U.S. shale plays. In the first case study from a pilot shale well in the northeast, natural fractures are identified on the new microelectrical imager and then further interpreted as open, partially open or healed fractures based on the inverted standoff images. Such open fracture interpretation has been validated by ultrasonic image data from the same well. In the second case study from an Eagle Ford Shale lateral in south Texas, both natural fractures and sub-seismic faults were detected. Interestingly, one of the interpreted open faults based on standoff images was even evident on dynamic pressure data in a monitoring well nearby during the stimulation process.
Natural fractures can impact the shale reservoir quality, completion quality, or both, depending on the fracture types and intensity. Therefore, it is beneficial to have a reliable dataset to sort fractures by their type: open, partially open and healed.
Optimizing Separation Efficiency Of Produced Water Tanks By Installing CFD Designed Internals
Authors: Trofaier Nikolas , Weilhartner Alexander , Puchner Bernhard , Konieczny Jaroslaw , Friedl Nikolaus , Kuemmel Georg , Perez Oscar Alberto , Steinbrugger Anne , Markl Richard 
Published: September 2015

Abstract
Efficient produced water management has been a growing concern in the oil and gas industry over the last decades. Water cuts have risen and more oil fields are maturing. Therefore growing volumes of produced water have to be handled every year. The most common disposal option is reinjection into the reservoir. In order to reinject produced water it has to be treated. Produced water tanks (PWT) are usually applied as first stage separators in water treatment plants. The oil-water separation efficiency of PWTs can be improved by optimizing tank internals to reduce the load on downstream treatment units. This study shows the results of a Computational Fluid Dynamics (CFD) based optimization approach for various water tanks in mature oil field environments.
The concept centers on the induction of a tangential liquid movement in PWTs to maximize residence time for a given volume of water and to reduce short-circuiting. In order to show the benefits of such a setup, an existing tank was upgraded with CFD designed internals. The separation efficiency of the tank was recorded prior to and after installing the internals. The results showed that the average residence time could be extended eightfold.
Based on the initial experience and additional simulation work, the internals concept was adapted and improved for several new tanks. These tanks are currently under construction and first field results will become available in 2016.
The Effect of Bit Type on Reactive Torque and Consequent Toolface Control Anomalies
Authors: Ledgerwood L. W. , Spencer Reed W. , Matthews Oliver , Bomidi John A. , Mendoza J. A. , Hanson Jonathan M. 
Published: September 2015

Abstract
The oil and gas drilling industry has developed a large body of knowledge about methods for drilling directional wells with steerable motors. Experience indicates that more aggressive drill bits are harder to steer. This is commonly attributed to the fact that bits with higher aggressivity produce larger torque changes for a given change in bit weight. The actual mechanics, however, of toolface disorientation during slide events is poorly understood. This paper reports on tests conducted on a full-size drill rig aimed at understanding the mechanics of toolface control. Toolface orientation and other data were measured downhole at 100 Hz. Nine different bits ranging from PDC to hybrid to roller-cone bits were tested on a motor/AKO BHA in slide mode. These tests confirm the common industry notions about the effect of aggressivity on toolface control. They also show that angular motion of the BHA while sliding is overdamped. Toolface orientation consequently follows the average of the torque signal generated by the bit. Furthermore, the toolface orientation is more easily disoriented by a torque signal at a frequency near or less than the natural frequency of the drillstring. PDC bits excite this more readily than bits with rolling cones. We also identify a toolface disorientation anomaly which we call a fast torque anomaly (FTA). FTAs occur because the bent motor/AKO has a preferred angular orientation in the borehole. FTAs have not been previously recognized, probably because they are not identifiable in mud-pulse signals. A BHA suffering FTAs would simply appear as a chaotic and profound loss of toolface control in mud-pulse data. Hybrid and roller-cone bits caused fewer FTAs than PDC bits.
Radio Frequency Identification (RFID)-Enabled Circulation Sub Precisely Spots Loss-Circulation Material in Critical Interval
Authors: Valverde Eddie , Reitsma Rienk , Hutchings Travis 
Published: September 2015

Abstract
Taking fluid losses in a drilling operation is common practice. Pumping loss-circulation material (LCM) to control drilling fluid losses to the formation is part of the overall solution. Precisely spotting the correct volume of LCM and protecting sensitive directional tools in the bottomhole assembly (BHA) has proven to be a considerable challenge.
Recently in a critical offshore well in the North Sea, the 6.5 intermediate section was drilled to 10,446 feet through a soft, porous limestone formation. In addition to the propensity of the chalk formation for seepage, a pre-existing natural fault was also present. The drilling fluid used to drill this section was 8.7-ppg paraffin- and mineral-based mud. Factors key to controlling losses were LCM displacement in precise intervals of the section and timely delivery of the material into the well annulus through a diverter circulation sub. High flow rates and minimal differential pressure at the tool were key to the mud program.
Because the RFID-enabled diverter circulation sub was capable of being selectively opened and closed using specifically programmed transponders, it did not require a ball seat or mechanical indexing system. This feature, coupled with the extra-large total flow area (TFA) and integrated flapper system of diverter circulation sub, allowed precise and timely LCM pumping while completely protecting the measurement-while-drilling (MWD) and rotary steerable (RSS) systems from damaging debris.
A total of 29 pills were pumped in the 14-day period that it took to drill the section. The circulation sub was strategically opened and closed in the diverting mode during this pill and LCM pumping program to control losses and allow the operator to drill ahead. By using an RFID-enabled circulation sub specifically designed to displace heavy pills and LCM, the operator was able to control losses, maintain proper hydrostatic pressure, and reach total depth (TD).
Microseismic-Derived Expected Ultimate Fracture Half-Height Above/Below Wellbore in Unconventional Stimulated Reservoir Volume in a Multi-F ractured Horizontal 10 Well Pad - Canadian Horn River Basin Case Study
Authors: Virues Claudio , Budge Jessica , Lunen Eric von 
Published: September 2015

Summary
Over the past decade, microseismic (MS) monitoring has become the primary approach used to gain an in-situ understanding of the rock's response during stimulation. Recently, the utilization of downhole monitoring of treatments has provided an opportunity to investigate ways by which these fractures develop by examining microseismic events recorded during stimulation. In the Horn River, geophysicists and engineers used microseismic field data and its interpretation to constrain reservoir models. Generally, it has been observed that fracture height, width and length vary from formation to formation.
In the presence of uncertainty in reservoir models, input data is required for determining the best estimate of a value, and probabilistic methods are used. Risk analysis is a technique used to quantify the impact of uncertainties on output variables, and to determine a range of possible outcomes. In this paper we use Monte Carlo simulation and probability density functions (PDFs) that describe likely values of fracture half-height as an input parameter into reservoir models. PDFs and Cumulative Distribution Functions (CDFs) are used to provide realistic estimates of stimulation parameters, such as stimulated reservoir volume.
Microseismic interpretation of events provides an upper bound value for fracture half-height in unconventional shale gas reservoirs. Its CDF for each well on a multi-fractured horizontal well pad provides a better understanding of what the ultimate fracture half-height could be after pressure depletion, and what the resulting implications for well spacing/ placement in pad design are. This facilitates a probabilistic approach to production forecasting and reserves estimation, and allows us to calculate a robust estimate range of estimated ultimate recovery (EUR) and recovery factor (RF). This approach differs from previous work that is based on strong collaborative work between geophysicists and engineers.
This paper contributes technically to the knowledge of the unconventional shale oil and gas industry by constraining analytical models that can be used as a quick look/ first pass into numerical simulation, and as estimators of production forecasts and different reserves categories. Furthermore, some of the design considerations of the multi-well pad, in addition to surveillance data – such as production logs, chemical fluid and radioactive tracer – will be addressed, concluding with a discussion of the results.