bluuebunny/crossref_metadata_2025_split huggingface dataset:
Predicting Failures from Oilfield Sensor Data using Time Series Shapelets
Authors: Patri Om Prasad , Panangadan Anand V. , Chelmis Charalampos , McKee Randall G. , Prasanna Viktor K. 
Published: October 2014

Abstract
Increasing instrumentation of the modem digital oilfield produces streams of data from sensors that monitor the functioning of different components in the field. This data should be converted to actionable information rapidly in order to respond to events as they happen or are predicted. The challenge is therefore to develop technologies that can process these large sensor datasets rapidly and with minimal manual supervision to ensure a data processing system that can scale with the increasing instrumentation.
We consider as a use-case an oilfield with several Electrical Submersible Pumps (ESPs), each instrumented with sensors that continually measure electrical properties of the pump (the streams of sensor data), which are then relayed to a central location. In this paper, we demonstrate how a time-series analysis approach can be applied to failure detection and failure prediction from the streams of sensor data. The method involves identifying "shapelets" – short instances that are particularly distinct – in the streams of sensor data.
The shapelets approach is particularly applicable to large oil and gas enterprise datasets because the algorithm does not need access to the entire historical data. This greatly reduces the amount of data that needs to be stored for data analysis. Moreover, unlike model-based approaches, shapelet-based analysis does not make any assumptions about the underlying nature of the data, making it practical for applications where a detailed physical model of the pump is not available.
We validate our proposed method by analysis on a representative set of instrumented ESPs. We describe the preprocessing steps that were applied in our analysis. We report the results of experiments to study the effects of varying the data processing parameters on the accuracy of fault detection and prediction. These results indicate that shapelet-based approaches are promising for analysis of time-series data in the oil and gas industry.
The MPD Well Control Matrix: What is Actually Happening
Authors: Rajabi Mehdi Mir , Hannegan Don , Moore Dennis 
Published: October 2014

Abstract
When drilling conventionally, upon indication of an influx, the drill string is lifted off bottom, circulation is stopped, a flow check is performed, and if the well is flowing, the well is shut in. The influx is then circulated out through rig choke using a reduced circulating rate.
With Managed Pressure Drilling (MPD), when kicks occur, they are typically smaller, contained more quickly, and, in some cases, they may be circulated out through MPD equipment without drilling or circulation interruption. The IADC MPD sub-committee has drafted a Well Control Matrix (WCM) in an effort to offer guidelines on when it is acceptable to kill the well dynamically when practicing CBHP MPD.
Rotating Control Devices (RCD) are commonly used on conventional overbalanced mud programs. To many in the industry, no specific distinction is made or special name is given to this type of operation. Confidence acquired over time has encouraged the common practice of drilling ahead while kicks are being circulated out, in appropriate circumstances. An influx, with only a very basic equipment configuration and whether it's called MPD or not, has often been handled in the industry as a routine operation without any special preparation or a formal WCM.
If a WCM is to be required to be in place, it should be engineered properly. A methodology for developing a WCM will be discussed in this paper. Procedures to control influxes as well as how to determine when to revert to secondary well control equipment under these operating conditions and examples of practical applications will be discussed.
Talent Evaluation Paradigms
Authors: Martin Maria Jesus , Jones Deanna , Benson Sharon , Murphy Lynn , Jamaluddin Abul , Nolen-Hoeksema Richard , Hyde Amanda , Chhibber Ravi 
Published: October 2014

Abstract
Access to talent is a growing concern for most E&P companies as the industry focuses on new resource plays, new frontiers, and the adoption of new technologies. The average experience of engineers and geoscientists is decreasing. Consequently, E&P companies are re-assessing the strategic importance of talent development programs to transfer knowledge from experts to recent hires. Current technical talent development models focus on accelerating the development and transferring the domain knowledge, but they often exclude technology proficiency and technology-driven workflows to the developmental detriment of the newly hired engineers or geoscientists. Technology proficiency is essential for finding business solutions in today's data-driven E&P environment.
Using case studies, we compared and contrasted the two different approaches used to develop effectiveness and efficiency of the future petrotechnical experts (PTEs). To develop the effectiveness of PTEs, it is essential to assess their domain knowledge and identify gaps with respect to the capabilities required to execute a company's strategy. In contrast, to develop the efficiency of these PTEs, it is necessary to assess the current technical workflows and the proficiency of the PTEs in using the company's chosen technologies. Four key aspects of training were reviewed: company structure, employee domain knowledge, employed technology, and operational workflows. The assessment results highlight and validate issues that collectively impact the development of PTEs' technology proficiency and productivity.
This holistic evaluation approach ensured that the talent management recommendations were aligned with a company's strategy. Also, this approach highlighted the need for synergy between the human resource department and the senior technical community of the company. The assessment quantified the efficacy of existing talent development programs. Using the established capability and technology consumption gaps, the company was able to focus the investments made in sourcing and/or creating talent development programs.
Drillstring Network 2.0: An Enhanced Drillstring Network Based on 100 Wells of Experience
Authors: Craig Andrew , Adsit Rhys 
Published: October 2014

Abstract
Wired drill pipe (WDP) has been used in more than 100 wells worldwide to create a drillstring network that provides high bandwidth communications between the surface and tools deployed in the wellbore. This network operates independently of drilling fluid, enabling communications for the widest range of drilling applications, including drilling with foamed muds. In addition, the network provides real-time memory/wireline-quality data not only from tools in the bottom hole assembly but also from tools that may be arrayed at intermediate points along the drillstring.
Real-time data like this improves decision making, opens the door for advanced drilling processes such as automated drilling, and gives visibility to downhole conditions where never before possible. Indeed, the numerous deployments in which wired drillpipe has been used have demonstrated that the network provides significant value to the drilling process in terms of drilling safety, efficiency and performance.
Based on the learnings and experience gained across these operations, a new and enhanced version of the drillstring network has been developed. This second generation high-speed drillstring network includes improvements to the design of wired drillpipe, a new generation of distributed network electronics, and a graphical surface network controller. These enhancements and their utility with respect to improving drilling processes are discussed in detail. This paper is an update to SPE-167965 to include the latest field testing results.
These improvements are designed to create a more stable, robust and reliable network system. Further, the enhanced graphical surface controller expands network diagnostic capabilities and reduces the learning curve for network users. Revisions to the wired drillpipe design will result in lower cost of ownership and more cost-effective deployment of the technology, further improving the value the system can provide.
Acid Soluble Plugs – Pressure Tight Solution for a Pre-Perforated Liner
Authors: Livingston E. , Bjornen K. , Burkhead D. W. , Gilbert W. W. , Kent A. W. , Leitch J. , Zhou L. 
Published: October 2014

Abstract
This paper covers the development, laboratory testing, and field testing of Acid Soluble Plug (ASP) technology as a viable completion alternative to wireline or tubing conveyed perforating. The ASPs are installed in a pre-perforated reservoir liner and dissolve when soaked in acid allowing access to the reservoir. This allows the technology to be easily applied in reservoirs where matrix acid jobs or acid fracturing techniques are employed.
The ASP technology was developed to reduce risk and cost associated with wireline and tubing conveyed perforating. ASPs were designed, manufactured, and field tested in both 5 in. and 7-5/8 in. reservoir liner sizes for wells in the Ekofisk and Eldfisk fields. The combination of laboratory testing and large scale field testing influenced the design of the ASPs as well as the additives utilized in the acid systems used to dissolve them. From concept to initial field implementation, the process of ASP engineering development took more than two years.
The concept was initially field tested in deviated injectors with ASPs installed in the deepest section of reservoir liner. The field tests proved the ASP concept prior to depending on the technology in a horizontal producer with an un-cemented, liner-in-liner completion solution. The field tests showed that acid soaking dissolved the ASPs in the down hole environment and allowed efficient acid stimulation of the reservoir. It also reduced the number of wire line runs necessary to complete the well.
When field tested in a liner-in-liner completion application, installation of the ASPs in the reservoir liner eliminated tubing conveyed perforating runs. The reservoir liner was un-cemented with mechanical openhole packers for zonal isolation. The ASPs provided a pressure tight reservoir liner to set the packers against and eliminated fluid loss during the running of the inner completion string.
Optimization of this technology is an ongoing process. The plug design itself continues to evolve as well as the operational steps to minimize the soaking time necessary to dissolve the plugs and gain access to the reservoir. The latest field applications will be shared at the time the paper is presented.
Successful Acidizing Treatment of Four Offshore Wells with High Bottomhole Temperatures in Mobile Bay, Gulf of Mexico: Laboratory and Field Case Studies
Authors: Legemah Magnus U. , Bilden Dean , Lowe Crystal , Gomaa Ahmed , Xiaolan Wang , Qu Qi , Sun Hong , Boles Joel L. , Li Leiming 
Published: October 2014

Abstract
Acidizing high-temperature wells has always been a challenge due to problems associated with corrosion of tubulars and loss of acid carbonate dissolving efficiency. Typical acid treatments of offshore wells with extreme downhole temperatures are carried out using retarded acids, which often degrade, form insoluble salts, and require further neutralization of flowed back spent acid, resulting in loss of production days. Recently there has been a growing interest in using amino-polycarboxylic acids such as glutamic acid, N, N'-diacetic acid (GLDA) to treat carbonate or sandstone formations with high bottomhole temperatures. The benefits of using such acid for high-temperature acidizing are lowered reactivity, inherent chelation chemistry, better tubular protection and biodegradability.
Extensive laboratory testing was conducted before a field trial of the acid. A corrosion test conducted at 395°F using corrosion-resistant G-3 and G-50 coupons (identical to the metallurgy of the tubular) without corrosion inhibitor had a corrosion rate of 0.0068 and 0.0069 lb/ft2, respectively; thus, no corrosion inhibitor was included in the acid used for field treatment. About 2.38 pore volumes of the acid broke through a carbonate core, dissolving 452 mg of calcium at 300°F. A computed tomography scan of the treated core showed a highly branched wormhole distribution network. The acid was found to be compatible with brines and different elastomers often used in downhole completions.
Flowback samples of spent acid analyzed by ICP-OES contained a high amount of dissolved calcium, iron, and magnesium. Further neutralization of the flowed back acid was not required, saving the operator two or more days of production per well.
The successful removal of wellbore scale and formation damage in four offshore wells with bottomhole temperatures ranging from 395 to 410°F with an amino-polycarboxylic acid is presented. Detailed laboratory testing that supported the treatment design and field application will be reported. Production enhancement as a result of the treatments, statistical analysis of flowed back spent acid physico-chemical testing, challenges with the treatment process, and treatment design will also be presented.
Optimizing the Selection of Lateral Re-Entry Wells through Data-Driven Analytics
Authors: Popa Andrei S. 
Published: October 2014

Abstract
A new intelligent model that successfully learns from high-dimensional data and effectively identifies high production areas and optimum Lateral Re-Entry well candidates is presented. The model is entirely data-driven and uses WM rules extraction, fuzzy logic, pattern recognition and Voronoi mapping. We applied our model to a large field with thousands of wells and multiple production layers. We found that it significantly outperforms the previous methodologies, not only by identifying new production areas but also returning a two fold production increase in 2013 compared to prior approach.
The paper showcases a successful project focused on revitalizing poor performing vertical producers by sidetracking and drilling lateral sections into zones with remaining opportunity in order to improve margins and drain reserves more efficiently. The approach uses artificial intelligence technology tools to screen reservoir targets and generate potential candidates. In the first step WM rules extraction algorithms were run for each one of the main reservoir attributes (permeability, thickness, saturation, temperature, etc.) in the nine formations. The results were used to build a fuzzy decision system to generate a confidence index for each grid block in the 155 million cell full field earth model. Confidence index maps were created to pinpoint prime productive areas and help evaluate optimum directional paths. Lastly, Voronoi delineation were used to estimates a drainage area per well, remaining reserves and movable oil in place.
Applying analytics has breathed life into an asset previously thought to have limited growth potential. The future looks bright with a queue of hundreds of well candidates identified and awaiting execution over the next years.
X-ray Backscatter Imaging in an Oil Well
Authors: Spannuth Melissa , Esmaeili Morteza , Gunn Spencer , Ponce-Marquez David M. , Torsteinsen Henning , Voll Adne 
Published: October 2014

Abstract
A new wireline tool that creates X-ray backscatter images of objects within a production well has been developed. Using X-rays to produce images instead of the more conventional optical video recordings offers the significant advantage that the measurement is not hindered by the nature of the production fluid. Therefore, X-ray imaging does not require the well to be specially treated in any way, saving the time and costs associated with cleaning or replacing well fluids.
The tool generates hard X-rays (&gt;10 keV) and measures the backscattered radiation from objects and fluids directly in front of the tool using X-ray detector arrays arranged around the tool axis. Measurements of backscattered radiation are converted into three-dimensional renderings or two-dimensional images of the object using a novel fluid-based surface reconstruction technique.
Example images from operating the tool in a laboratory setting demonstrate the ability of the tool and technique to create reconstructions of objects in a variety of normal production fluids including clean water, saline water, oil, and fluids with suspended rust particles. They reveal the maximum practical imaging depth range from the bottom nose to be approximately 10 cm. The images also demonstrate the millimeter-scale resolution and accuracy of the tool.
The images were produced with a tool exhibiting a commercially viable outer diameter. Thus, this new X-ray imaging method and wireline tool can provide improved visualization and diagnostic capabilities for a significant number of offshore production wells while avoiding the expense and inconvenience of conventional imaging techniques.
Seismic Constrained Reservoir Simulation and Application in a Heavy Oilfield, China
Authors: Cai Yintao , Guo Xiangyu , Ling Yun 
Published: October 2014

Abstract
With the development of reservoir numerical simulation, especially thermal numerical simulation, people start to use thermal numerical simulation model to study the development and distribution of steam chamber in thermal recovery process. But as all known, there still are many uncertainties in the reservoir parameters and well parameters in thermal simulation model, such as the excessive variation of the fluid properties, the uncertainty of static model owing to reservoir heterogeneity and others. These uncertainties usually result in multiple solutions of simulation history matching or ambiguous simulation results.
To reduce multiplicity of history matching in reservoir simulation and better predict the development of steam chamber in the thermal recovery process, seismic constrained reservoir numerical simulation is proposed to incorporate both reservoir simulation and 3D seismic image result in the loop of reservoir simulation and history match. The procedure is discussed through the application to a heavy oil reservoir in which two times of 3D seismic surveys were acquired at the later stage of production, and reservoir numerical simulation was performed in the SAGD (Steam assisted gravity drainage) pilot block of the reservoir.
The proposed procedure includes following main steps: 1) The dynamic data is collected and analyzed for the preparation of reservoir numerical simulation, and an overall distribution of steam chamber is predicted approximately through reservoir engineering analysis; 2) A reservoir simulation model is initially built using available geological, petrophysical and engineering data, and primary history matching is then performed; 3)The reservoir simulation results from previous step and the time-lapse seismic imaging are interpreted comprehensively to find out the consistencies and differences about the steam chamber between them, which are related to history matching errors. 4) Based on these consistencies and differences, the possible factors (geological properties, petrophysical parameters, and rock thermal properties) which caused the history match errors are analyzed, and the corresponding parameters of the simulation model are modified accordingly, and then back to step 2 and 3 for the iteration until a relatively matched result proved by subsequent production data was received.
Application results proved that with the constraint of seismic image data, the reservoir simulation errors can be accurately located and the primary cause for it be determined, and then through reservoir simulation iterations the relatively accurate prediction of steam chamber as well as remaining oil is reached.
North Sea Case Study of an Integrated Sim2Seis Workflow
Authors: Tabatabaei M. , Milovac J. , Bastidas R. , Lau R. , Jameson E. 
Published: October 2014

Abstract
Simulation to Seismic (Sim2Seis) is a forward modeling technique used to predict/generate synthetic seismic response from a static or dynamic reservoir model. There are two key components of a Sim2Seis workflow: reservoir model (geological and/or simulation model) and petro-elastic models (PEMs). PEMs are rock physics functions which relate reservoir properties such as rock types, porosity and fluid saturation to the elastic properties such as compressional and shear velocities, and density. Predicted elastic properties are used to compute reflection coefficients, when convolved with a wavelet generate a synthetic seismic volume (1D or 3D).
There are several applications for Sim2Seis in reservoir characterization. It can be applied to test the consistency of a 3D geological static model, or of a history-matched simulation (dynamic) model with the actual seismic data. It can also be applied to study the impact of saturation change on seismic response (4D effect). A case study from an oil producing Tertiary age field in the North Sea was used to illustrate the applications of Sim2Seis workflow. This case study reveals the value of integrating the static and dynamic data for more accurate reservoir characterization, and consequently building a more reliable reservoir flow model which honors petrophysical and seismic data as well as production data.
Cement Evaluation - A Risky Business
Authors: Benge Glen 
Published: October 2014

Abstract
Cement evaluation is commonly thought of as running a cement bond log (CBL) and attempting to interpret the results to determine if there is isolation in the wellbore. Oftentimes that interpretation is made in isolation with little or no information on what occurred during the drilling and cementing of the well, or the cement systems used. Evaluating cement in older wells where the drilling report states, "ran casing, cemented same" can be particularly challenging.
Cement evaluation is much more than a CBL. Understanding the objectives of the cement job, the design limitations imposed by those objectives and the resulting slurry and job designs are all integral parts of cement evaluation. Oftentimes the selection of a specialty cement system to meet specific well requirements can dictate how the cement can be evaluated.
To properly evaluate a cement sheath, knowledge of the cement job, slurry designs and the limitations of the evaluation technique must be understood. To attempt to perform a cement evaluation based solely on the log output from a CBL, or any log, invites considerable error and bias into the resulting interpretation.
This paper reviews various methods of cement evaluation, from job data, casing and formation pressure testing through sonic and ultrasonic logging. The assumptions associated with each technique are outlined and the discussion includes the limitations of the various techniques along with cautions on how misinterpretation of the results can lead to assumptions of cement integrity that may not be appropriate.
The impact of new boutique cement designs, which incorporate high concentrations of inert materials to give the set cement unique properties, is discussed. The ability of specific logging techniques to evaluate the presence of these slurries is presented. Data on selected boutique cement systems where conventional UCA strength data is not representative of the crush strength of the cement due to the incorporation of specialty materials is included.
An overview of cement evaluation, and a risk based discussion of what technique may be most appropriate based on the cementing objectives is presented. Methods of reducing risk uncertainty in cement evaluation are discussed along with the "validity" of the various data sets available to the engineer to perform a proper cement evaluation on the well.
Understanding the objectives of the cement job sets the boundary conditions for the designs, and from those designs the ability to evaluate the resulting cement placement and well isolation can be determined. Setting the evaluation methodology and understanding the type of information required to apply that methodology can improve the quality of the evaluation.