bluuebunny/crossref_metadata_2025_split huggingface dataset:
Perforating Gunshock Loads - Prediction and Mitigation
Authors: Baumann Carlos , Lazaro Angel , Valdivia Paulo , Williams Harvey , Stecchini Paulo 
Published: March 2013

Abstract
Perforating wells calls for careful planning to maximize well productivity over the life of the well, and to prevent time and money losses due to unexpected side effects. A large class of wells and in particular high-pressure wells are susceptible to gunshock damage when they are perforated with inappropriate gun systems. This paper presents applications of a simulation methodology to predict gunshock loads for tubing-conveyed and wireline-conveyed perforating jobs. With this simulation methodology we can evaluate the sensitivity of gunshock loads to changes in gun type, charge type, shot density, cable size, tubing size and length, number of shock absorbers, rathole length, placement and setting of packers, and early reservoir response, among many others.
When planning perforating jobs, engineers strive to minimize the risk of equipment damage due to gunshock loads. With the simulation software presented in this paper, engineers can identify perforating jobs with significant risk of gunshock related damage, such as unintentional pull-offs, bent tubing and unset packers. When predicted gunshock loads are large, changes to the perforating equipment or job execution parameters are made to reduce gunshock loads to an acceptable level.
Fast gauge pressure data from perforating jobs shows that wellbore pressure transients can be accurately predicted. For well prepared simulation models, typical peak sustained pressure amplitudes at the gauges are on average within 10% of simulated values. In jobs where shock absorbers were used, residual deformations of crushable elements correlate well with predicted peak axial loads; which confirms that gunshock loads on the equipment are well predicted.
With the simulation methodology described in this paper engineers can evaluate perforating job designs in a short time, and they can optimize perforating jobs by reducing gunshock loads and equipment costs. The ability to predict and mitigate gunshock damage in perforating operations is very important because of the high cost of typical high-pressure wells.
Fit-for-Purpose BHA Design for Drilling Complex Wells Offshore Brunei Leads to New Industry Benchmark
Authors: Legarth B. , Dustin S. , Montero J. , Walker J. , Mulligan R. , Maeso C. 
Published: March 2013

Abstract
Some of the oil fields offshore Brunei are characterized by complex reservoir geology. This requires the drilling of high-complexity, tortuous 3D horizontal wells referred to as "snake wells" for optimal reservoir drainage. These wells deliver an ultimate recovery equivalent to multiple horizontal wells drilled in the same structure. This development concept was chosen as the most beneficial with the business value drivers for the Selangkir Iron Duke (SKID) project.
Over a period of several years, drilling performance had improved but plateaued and still contained hours of nonproductive time (NPT), including hole conditioning wiper trips, rough drilling causing bottomhole assembly (BHA) failures due to vibrations, troublesome trips, and even lost production due to stuck-pipe incidents. In previous "snake well" drilling campaigns multiple additions to the BHA design to overcome tight hole problems had seen an ever more complex and rigid BHA being adopted, but without the required NPT or well cost reductions.
In an attempt to make a step change in performance the BHA design and drilling processes have undergone a comprehensive revision. The primary focus areas were to enable shoe-to-shoe runs, reduce the risk of stuck pipe, improve tripability of BHA, reduce torque and drag and last but not least improve the overall hole section progress. A more flexible, slimmer rotary steerable system (RSS) BHA design having a shorter, compact sourceless logging-while-drilling (LWD) tool was proposed to reduce damaging vibrations and ease tripping.
The paper discusses engineering solutions implemented to mitigate risks associated with complex well geometries which consequently contributed greatly to deliver the high-complexity extended-reach drilling (ERD) wells with top quartile and even best-in-class performance in the Rushmore's Drilling Performance Review (DPR).
Little Things, Big Effect-Identifying Causes and Addressing Vibrations Issues in Challenging Deepwater Applications
Authors: Mensa-Wilmot Graham , Benet Paul , Ramchune Devanand , Maddoux Blake 
Published: March 2013

Abstract
As performance dysfunctions1, Vibrations2 have drastic consequences on drilling operations. The challenges presented by vibrations get amplified on deepwater drilling programs. Vibrations cause downhole tool failures, thereby forcing multiple bottomhole assembly (BHA) trips. In some instances, connections become over-torqued and cannot be broken out on rigs. This situation creates logistical problems for service partners and operators alike (due to the requirement to have multiple back-ups for various tools), and with huge implications on project costs. Vibrations also create drilling inefficiencies with regards to borehole verticality and directional performance. Considering the total measured depths (TD) on deepwater projects, borehole verticality is usually a critical operational requirement. In other instances, the need to achieve specific wellbore trajectory requirements directionally based on project specifics also becomes critical. As a result, rotary steerable systems (RSS) are commonly used on these projects. However, and as documented extensively, vibrations compromise achievement of these goals even when RSS tools are used. Additionally, vibrations have negative effects on rate of penetration (ROP). This is why vibrations control continues to preoccupy the industry, particularly on deepwater projects. Considering the complexities associated with these projects and their much higher rig and spread rates, vibrations control is critical for project success.
The Use of Along String Annular Pressure Measurements to Monitor Solids Transport and Hole Cleaning
Authors: Coley Christopher J. , Edwards Stephen T. 
Published: March 2013

Abstract
For many years the oil industry has been limited by the fact that measurements are only taken at the BHA and at surface during well construction operations. This has led to a reliance on modeling to help understand the measurements made and to understand the conditions in regions of the wellbore that are not being directly monitored. The advent of sensors that can be deployed along the drill string has created an opportunity, for the first time, for operators to observe the downhole environment not just at the BHA but throughout the entire wellbore.
In order to realise the value of these measurements it is necessary to expand existing analysis techniques and develop new methods specifically designed to make use of this expanded sensor capability. BP was the first operator to commercially deploy the along-string measurement sensors in a development well (2008) and has been making use of the technology ever since. This paper presents some of the analysis methods used in these deployments as well as some of the lessons learned. It is shown that, while the addition of along-string sensors can increase the complexity of analysis, the information that can be gleaned from this data can be very valuable.
BOP Testing - Qualification Tests, Test Facilities and the Efficient Means of Operating Them
Authors: Springett F. B. , Johnson C. , Shah M. 
Published: March 2013

Abstract
In the world we know today, BOP performance is in the limelight all the way from the manufacturers to governmental levels. Greater performance objectives require higher testing standards. Testing and qualification of BOP equipment as dictated by API 16A involves facilities with the capability to test BOP's in multiple environments and operating scenarios. This paper will discuss the test set up for each type of test, the criteria for acceptance and the type of facility required to perform it. The types of tests to be discussed as defined in API 16A are fatigue testing, high temperature, low temperature, stripping, hang off, sealing characteristics, shear testing etc. The paper will also discuss some of the potential future testing requirements as well as the equipment required to perform it based on industry discussions of these requirements. Finally, the paper will discuss the process by which a multimillion dollar R&D lab was developed and operated from the ground up. It's not only about capability; it's about capacity. Applying manufacturing principles to the design and operation of an R&D Test facility achieved significant gains in the quality and output of tests performed. In summary, this paper will examine the needs of a modern BOP test facility and the methods used to deliver on those needs effectively.
Upstream E&P and Drilling Safety and Optimization – Lessons from the BioPharma R&D Industry: The Role of Translational Analytics and Informatics
Authors: Madhavan Suresh , Dalgliesh Jeff , Kimball Jon 
Published: March 2013

Abstract
There is an uncanny resemblance between the Upstream Oil and Gas Exploration and Production (E&P) industry and the BioPharma R&D Industry, which discovers, develops and markets drugs and vaccines. This paper will describe these comparisons; discuss some of the new trends in the BioPharma industry and show why there are lessons there that are just as valid and important to the Upstream Oil and Gas industry: Translational analysis across traditional development (departmental) data silos to get a better understanding of the underlying nature of the asset being developed is important. ○Discovery, Nonclinical, and Clinical development of a drug candidate in Pharma R&D;○Earth Science, Reservoir, Drilling and Production data in Upstream Oil and Gas of a potentially producible oil field.The BioPharma industry has recognized the need to extract enriched metadata and patterns from collected raw data; and it is now moving towards building models with these patterns for decision making. ○This is relevant for the Oil and Gas industry particularly for drilling safety and prediction.Dealing with disparate data types and their volumes has proven difficult with traditional data warehouse technologies and elusive in meeting the goals of a flexible innovation platform for the future.
Distributed Acoustic Sensing: State of the Art
Authors: Cannon Robert , Aminzadeh Fred 
Published: March 2013

Abstract
Distributed Acoustic Sensing (DAS) is a newly developed passive fiber optic sensing technology. It has the ability to detect acoustic signals anywhere along the length of the fiber with a high frequency response and a tight spatial resolution. DAS has a bright future within the upstream oil and gas industry though it is currently not well understood as it is such a new technology. This paper will first provide a thorough discussion of the technology&#39;s functionality including the factors that influence its frequency response and spatial resolution as well as how to directly calculate these parameters. Next, the paper will discus both proven and unproven applications of DAS technology. The current proven applications are near well-bore hydraulic fracture stimulation surveillance, flow profiling, well integrity monitoring, vertical seismic profiling, gas-lift optimization, sand detection, and ESP monitoring each of which are discussed in contrast to current alternative techniques. Case examples are summarized for each of these applications. Some of the unproven applications of DAS are summarized like multi-phase flow measurements and microseismic monitoring.
Synthetic, Geomechanical Logs For Marcellus Shale
Authors: Eshkalak M. O. , Mohaghegh S. D. , Esmaili S. 
Published: March 2013

Abstract
Successful recovery of hydrocarbons from the reservoirs, notably shale, is attributed to realizing the key fundamentals of reservoir rock properties. Having adequate and sufficient information regarding the variable lithology and mineralogy is crucial in order to identify the "right" pay-zone intervals for shale gas production. Also, contribution of mechanical properties (Principal stress profiles) of shale to hydraulic fracturing strategies is a well understood concept. It may also contribute to better, more accurate simulation models of production from shale gas reservoirs.
In this study, synthetic geomechanical logs (Including following properties: Poisson&#39;s Ratio, Total Minimum Horizontal Stress, Bulk and Shear Modulus, etc.) are developed for more than 50 Marcellus Shale wells. Using Artificial Intelligence and Data Mining (AI&DM), data-driven models are developed that are capable of generating synthetic geomechanical logs from conventional logs such as Gamma Ray and Density Porosity. The data-driven models are validated using wells with actual geomechanical logs that have been removed from the database to serve as blind validation wells. In addition, having access to necessary data to building a geomechanical distribution (Map and Volume) model can assist in understanding the rock mechanical behavior and consequently creating effective hydraulic fractures which is considered to be an essential step in economically development of Shale assets.
Moreover, running geomechanical logs on a subset of wells, but having the luxury of generating logs of similar quality for all the existing wells in a Shale asset can prove to be a sound reservoir management tool for better reservoir characterization, modeling and efficient production of Marcellus Shale reservoir.
Efficient Use of Methods, Attributes, and Case-Based Reasoning Algorithms in Reservoir Analogue Techniques in Field Development
Authors: Temizel Cenk , Dursun Serkan 
Published: March 2013

Abstract
Decision making in field development has been crucial in petroleum exploration and production activities where numerous uncertainties exist in the complete process. In the development process of new fields, any additional data to minimize uncertainty is important, as it decreases risks and provides better insight and robustness in decision making. Reservoir analogue techniques provide valuable information in this process. In the reservoir analogue method, oilfield historical data is used along with descriptive statistics and case-based reasoning as a guide or tool in carrying out field-development scenarios, which enables the field-development teams to make decisions while knowing the limitations of past real-life performances in fields. This will greatly help field-development teams make decisions based on what to expect economically, as they will have a reference on recovery factors and other indicative parameters to make more informed decisions on optimization parameters and field development. With advancements in technology and data-driven techniques, data has become more readily accessible; however, turning data into knowledge has become a challenge. Using reservoir analogues is not a new concept; however, the rationale in finding the analogues has not been studied or published in detail so far. The reservoir analogue technique involves a delicate use of categorical and parametrical attributes, classification of attributes, along with strong engineering judgment on individual cases. Thus, illustration of the proper use of algorithms plays an important role in obtaining successful results. In our paper, we proposed two approaches employed in the case-based reasoning system to find the reservoir analogues, where each reservoir is represented by not only numerical attributes but also categorical attributes. In each approach, several different distance metrics and similarity measures for numerical and categorical attributes, respectively, are studied.
Benefit Evaluation of Keeping an Integrated Model During Real-Time ESP Operations
Authors: Denney T. , Wolfe B. , Zhu D. 
Published: March 2013

Abstract
In most electric submersible pump (ESP) applications, a great deal of time and effort is spent upon the initial sizing of the ESP – projecting which equipment is most appropriate for the physical properties, reservoir delivery, and operator economics of the particular application. After the ESP is designed, ordered, and installed, however, the sizing is often placed in a repository and not referred to again until the ESP has failed and the next ESP is being designed. By integrating the design model into a real-time monitoring environment, more value can be demonstrated. Information that is particularly valuable include the evaluation of operating point versus design point, ESP diagnostics alarms, virtual monitoring and alarms, and monitoring of sub-component design thresholds. In this paper, we will review ESP design software in general, the benefits of implementing a real-time model comparison tool, demonstrate several cases, and conclude with a discussion of the challenges associated with managing the models. Additionally, we will examine how sizing can be used to optimize production and make adjustments for system enhancement.
Information Technology and Field Data Required to Successfully Manage Shale Production Operations
Authors: Farid Kemal , Bhatti Kashif , Fuge Clara , McLaughlin Sharon , Nichols Dana , Dassinger Janet 
Published: March 2013

Abstract
This paper will review the unique challenges of field data management and the technologies used to meet them in unconventional resource operations. Examining the lifecycle of field data, we will look closely at issues of data quality, analytics, enterprise data availability, integration, and regulatory compliance from the perspective of shale operators.
Responding to the high decline rates of wells, factory drilling in unconventional plays results in high-paced operations and a large number of wells. With these come massive volumes of field data that must be captured, processed and turned into actionable information for surveillance, operational accounting and HSEQ compliance.
Field teams collect fluid volumes and operating conditions at the well site along with run tickets, tank battery inventories, sales volumes, equipment status, and chemical use. Increased sensitivity to environmental issues around shale plays require operators to closely manage water, emissions and other environmentally impactful measurements that must be collected, monitored and reported. To accommodate these requirements, shale operators need IT systems flexible enough to capture any information that might be needed. Mobility solutions are increasingly being implemented as an enabling technology for capturing the data in the field and communicating it to the systems and users who must process and act upon the resulting information. The use of mobile devices helps eliminate paper, saves time spent on data entry and improves the quality of data flowing into ERP and technical systems.
Maintaining the quality of the information gathered is a constant concern. Poor data leads to costly results, from un-optimized production to fines for inaccurate reporting. Incorporating validation checks and approvals into the field systems promotes consistency and accuracy as data is being gathered. Asset specific variances, alerts and visualization can immediately identify operational issues. Access to production targets via mobile devices keeps the field team aligned with corporate goals.
Once gathered, raw production measurements collected in the field are processed to produce allocated production volumes at each well and zone. Consumed by different departments across the company, the allocated volumes are used for planning, forecasting, operations management, revenue accounting, marketing, regulatory and partner reporting. Operators must have an effective production data management system to provide the resulting information to a variety of users at the time, place and in the format they require.
Field information is at the heart of operations management for any operator. The issues around collecting, analyzing and sharing it will be examined along with the technologies employed to provide the best solutions appropriate for shale plays.
Practical Application of Integrated Reservoir Evaluation and Production Optimization in a Mature Waterflooded Reservoir
Authors: Qin Bin , Wang Zhiqiang , Garcia Jacoby 
Published: March 2013

Abstract
The development of mature waterflooded reservoirs to maintain long term and steady production while maximizing ultimate recovery has enormous challenges. The primary challenge to optimally develop waterflooded reservoirs is to enhance production per well while preventing the water-cut from rising too fast after adjusting the reservoir scheme and well operation parameters. Fulfilling this challenge requires the capability of integrating data associated to formation, wellbore and surface/facility sub-systems in order to comprehensively evaluate reservoir potential and optimize production while processing and analyzing large amounts of data.
This paper presents a methodology to address this challenge with a streamlined workflow by: (1) Characterizing reservoir properties and baseline existing well and surface/facility designs; (2) Correlating reservoir characteristics with production and injection history; (3) Identifying underperforming wells; (4) Assessing production enhancement possibilities; (5) Redesigning optimum operation parameters for candidates; (6) Then, proposing adjustment measures for injectors based upon injectivity analysis; and (7) Adjusting surface/facility designs with the enhancements.
A case study is presented to illustrate the effectiveness and benefits of this methodology. This study is based on gathering, validating and integrating sub-system data into a database-based application to systematically construct an integrated reservoir and production model. A combination of graphical, statistical, theoretical and simulation analysis tools were employed to identify: abnormalities, enhancement candidates and infill drilling opportunities. Analyzing the integrated subsystems ensured both: the reasonableness of the optimization design and the feasibility of adjustment recommendations. To validate the approach, a field pilot application was implemented on a waterflooded oilfield in western China, which resulted in a 15 percent increase in production of 3200 barrels per day. The study fully demonstrates that the methodology is suitable and practical to optimize production from such complex reservoirs.
Analytics in Oil and Gas: The Big Deal About Big Data
Authors: Feblowitz Jill 
Published: March 2013

Abstract
This report examines the potential for Big Data and analytics in the upstream and midstream sectors of the oil and gas industry. IDC Energy Insights provides insight on areas where Big Data and analytics has the potential to provide business value. This report covers newer technologies, such as Hadoop/MapReduce and streaming analytics, rather than the more traditional high-performance computing. The survey data is provided from oil and gas respondents based in the United States. Guidance is provided to CIOs, enterprise architects, IT strategists, and business executives on the potential of this new technology for the oil and gas industry.
Just like other industries, the oil and gas industry is experiencing an increase in the number of sensing devices in the oil fields or pipelines. Of course, the industry has always been plagued with too much data and the inability to make productive use of that data. What has changed in the past few years is the availability of new technology based on commodity hardware – Big Data and analytics – pioneered by firms like Facebook and Google.
This new technology can process high volumes of various types of data at relatively quicker speeds than conventional technology. Now, oil and gas CIOs are considering whether to invest in a Big Data and analytics infrastructure. This report reviews the current attitudes toward Big Data and analytics in the oil and gas industry and explores potential applications of the technology with an eye toward speeding time to first oil, reducing costs and increasing the safety of drilling, and enhancing production.