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Results
Future Workforce Education through Big Data Analysis for Drilling Optimization
Zhou, Y.. (The University of Texas at Austin) | Baumgartner, T.. (The University of Texas at Austin) | Saini, G.. (The University of Texas at Austin) | Ashok, P.. (The University of Texas at Austin) | Oort, E. van (The University of Texas at Austin) | Isbell, M. R. (Hess Corporation) | Trichel, D. K. (Hess Corporation)
Abstract On their continuous quest to improve drilling efficiency, operators are reaching more and more towards the sensor and data-streaming technologies and their powerful data analytics capabilities. For this project, an operator partnered with the drilling automation research group at the University of Texas at Austin to develop a workflow for big data analysis and visualization. The objectives were to maximize the value derived from data, establish an analysis toolkit, and train students on data analytics—a necessary job function of any future drilling engineer. The operator provided data sets, business and technical objectives, and guidance for the project, while a multi-disciplinary group of undergraduate and graduate students piloted an analysis workflow. The students developed methods to: 1) understand and clean the data; 2) structure, combine, and condense information; 3) visualize, benchmark, and interpret the data, as well as derive key performance indicators (KPIs); and 4) automate these processes. The operator provided data collected from drilling 16 wells in an US unconventional play. The large data sets comprised of un-organized time and depth based information from surface and downhole sensors, daily drilling reports, geological information, etc. Students were trained on specialized software and subsequently curated data into smaller sizes and standard formats. Students investigated bottom hole assembly (BHA) and directional drilling performance using a combination of auto-generated conventional visuals (e.g., BHA designs, annotated time vs depth curves) and newly developed tools (e.g., tortuosity, 3D well trajectory plots combined with operational data). Methods for ‘push a button' investigations of mechanic specific energy (MSE), vibration, torque and drag were also developed by calculating specific KPIs from the raw measurement data. The analysis work itself coupled with the attempt to improve the workflow processes served as a meaningful and highly effective way to educate students and prepare them to be the "drilling engineers of the future" with proficiency in data analytics.
- North America > Canada > Saskatchewan > Williston Basin > Bakken Shale Formation (0.99)
- North America > Canada > Manitoba > Williston Basin > Bakken Shale Formation (0.99)
Abstract Objectives/Scope Today, during the development of unconventionals, lack of knowledge about the downhole dynamics environment creates a culture of conservatism where excessive safety margins need to be applied to prevent damage to the rig equipment, drill bits, drill string and sensitive drilling tools. By using a combination of high-speed downhole data, surface applications, and an automated control system, this risk can be reduced, drilling performance improved and non-productive time reduced. Unconventional wells are typically drilled with several different types of drive systems, so on this project the impact of the automated drilling system was methodically tested in combination with the following BHA drive types: Conventional motors Rotary steerable tools Downhole motorized rotary steerable tools. Methods, Procedures, Process This paper discusses the test program implemented across a drilling in the Eagle Ford unconventional shale formation in South Texas. It was essential at the pre-planning phase that key performance indicators were identified and a solid test plan was designed. A road map was put in place to fully analyze the performance benefits where the automated drilling applications were tested against drive system, formation type and wellbore geometry. The primary objectives were to identify which applications combined with which drive system delivered the largest, consistent performance gains and the greatest cost savings. The paper includes a detailed description of the various automated applications tested: A surface-located, active stick-slip mitigation device A closed-loop high-speed downhole weight on bit controller Results, Observations, Conclusions These technologies bring significant benefits to our industry, especially in the development of unconventional assets where it is becoming increasingly difficult to deliver step changes in performance with current crews and technology. The high-speed downhole-driven control of the rig equipment allowed the driller and the customer representatives to maximize the performance of the rig without compromising safety or the reliability of the equipment. Drilling with automated motor BHAs and automated non-motorized rotary steerable BHAs allowed for repeated improvements in drilling performance of , well on well. The fact that this performance increase is repeatable offers significant bottom line value for operators, by allowing reliable well delivery, forecasting and overall reduced well cost. Novel/Additive Information Downhole-automated drilling control described within this case study is a powerful tool to be used by existing drillers and directional drillers. The drilling crew must use the automated control system in partnership with specialized automated drilling applications to realize higher performance, without sacrificing safety margins or tool life. Even with an automated drilling system, optimum performance is measurably more difficult to achieve without optimal BHA design and drive type.
Abstract This paper presents a model which aids the decision making process to determine the optimum point to trip out of hole to change a dulled drill bit. Drill bit interaction with abrasive rock and impact damage due to vibrations causes the state of wear or damage to cutters to increase. This results in a slower rate of penetration (ROP) than with a new bit with sharp cutters. The operator faces the question whether or not to take the time to pull the bit out of hole and change it for a new one. A delayed or a premature decision of when to pull the bit can add to the overall project cost. In the past the decision has been made using either the operator's experience or a simple cost model projecting a single bit run into the future. The model presented in this paper optimizes the bit strategy for an entire well with multiple bit runs to obtain the most economical choice of bits and bit trip strategy. The model can be used during planning, in real time implementation and for post well performance analysis. In particular, during real time and post run evaluation the model can be used for performance benchmarking of ROP by comparing an expected rate of progress with the actual field data. This paper further presents a case study highlighting the value of each of the features of the model including potential time and cost savings. It shows that running the model real time can reduce well costs significantly in hard rock areas. The deployment of the model is not limited to any specific application and can save costs on any well where the operator has a requirement for multiple bit runs and a good understanding of drilling performance through numerous geological intervals.
Abstract The concept of enterprise level and standardised realtime data management solutions supporting drilling operations is rapidly gaining considerable recognition with dynamic and technology-comfortable Operators. Whether delivered physically in an Operations Centre or virtually via web browser, the business drivers are clear – when presented in an ergonomic fashion, the full suite of realtime drilling and geology data enables timely, informed and collaborative decision-making, leading to performance improvement and reduction in operational, and therefore financial, risk. However, there remains a common disconnect between: (i) primary measured and processed real-time data, (ii) unstructured data in the form of analytical results, and (iii) tertiary metadata from reports. Typically these three tiers of data, and the companies providing them, are isolated from each other. Once operations commence, dataflow may occur in one direction with realtime data feeding into analytics and reporting tools, accompanied by substantial subjective human input. This paper discusses how a major European independent Operator, with a diverse range of global assets and associated challenges, has worked with its various data solution providers to develop and implement a fully bidirectional ‘data highway’ in which realtime, analysed and reported data are seamlessly and efficiently exchanged. This holistic approach to data-driven operations support delivers a combined value far greater than the sum of the individual applications, as the various proprietary systems enhance and complement each other. Non-productive time (NPT), as well as Invisible Lost Time (ILT) analysis, is fed back into realtime monitoring, reported comments are tied to realtime curves, planned and modeled drilling optimisation recommendations are displayed and correlated alongside live drilling data. Carefully mapped dataflows drive workflows which in turn drive sophisticated deliverables that improve standard operating practices, and hence best practice. The result is improved drilling key performance indicators (KPIs) leading to performance improvement, risk mitigation and cost efficiency: All at an enterprise level and all in realtime.
During the SPE ATW on Automation (April 13-14, 2010 in Galveston), it was identified that one of the major opportunities in the Drilling and Completions industry is the identification of non-planned events, ncluding invisible lost time with the objective to improve performance by building a value added propositionn that involves operators, service companies, contractors and equipment manufactures. The key point was to share risk and reward by using an unbiased system that is able to accurately measure, in an automated form, most of the routine drilling and completions operations that will bee compared against pre-agreed benchmarks to establish if the goals and objectives are being achieved. The technology presented in this paper explains how automatic operations detection are carried out to address the proposed challenges and the necessary reporting and user interactionn needed. The theory and onee case history on this will be presented and will cover the start up phase of such initiative, and all of its push backs, and lead the readers through the implementation and final results that were successfully achieved. Introduction Drilling and completion activities are typically categorized in several major groups, which are derived from using the time versus depth curve to describee the drilling process.
SPE/IADC 140172 Anatomy of the "Best In Class Well": How Operators Have Organised the Benchmarking of their Well Construction and Abandonment Performance This paper was selected for presentation by an SPE/IADC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers or the International Association of Drilling Contractors and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers or the International Association of Drilling Contractors, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers or the International Association of Drilling Contractors is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE/IADC copyright. Abstract The use of comparative performance data by operators to drive well construction performance improvement is a powerful and proven technique. Offset well data is also used by operators for a range of other applications. Twelve operators came together in 1989 to organise the sharing of drilling offset data between themselves, in order to remedy the deficiencies experienced in obtaining this data from other sources. This has grown into a global programme with data shared on over 38,000 wells provided by over 200 operating companies in 80 countries (Appendix 1 and 2). As well as the initial drilling study, data are also shared in studies looking at the completions and well abandonment phases. Every super-major, most of the large and mid-sized international operators, many independents and a number of national oil companies participate in one or more of these studies. It is the aim of the participating operators to grow the programme to ultimately collect data on all hydrocarbon wells constructed globally. This paper describes why operators have chosen to share comparative performance data amongst themselves, the way in which this is organised and the data itself. It examines the analysis and normalisation tools employed as well as the quality controls in place to ensure data integrity. Operators use the data for benchmarking and other applications, all focused on improving planning and operational performance. Introduction Operators need reliable offset well data for a range of applications which are described below.
- South America (1.00)
- North America (1.00)
- Europe (1.00)
- (2 more...)
- North America > United States > California > Union Oil Field (0.89)
- Europe > United Kingdom > North Sea (0.89)
- Europe > Norway > North Sea (0.89)
- (2 more...)
Abstract Drilling programs continue to be pushed into harder and more abrasive formations. In addition, directional drilling activities, with the on-going surge in deployment, have become more complex. Well depths, profiles, dog-leg severity (DLS), departures, and the other associated parameters, are continuously been pushed into newer and more challenging frontiers. Consequently, and as a result of these factors, sharp operational cost increases are being recorded. The resulting economic impact challenges the practicality of the industry's push for oil and gas in harsher environments. Considering the undeniable need to find new oil and gas reserves, the cost increases must be reversed. Performance drilling, when effectively implemented, will serve as one of the enablers that facilitate achievement of this objective. This paper will define and establish the framework for performance drilling (PD). In addition to identifying performance qualifiers (PQ), it will also establish their dependencies and relationships. The significance of offsets, especially in the benchmarking process will also be discussed. Drilling efficiency will be analyzed and differentiated from rate of penetration (ROP) maximization. Value creation, measured in terms of drilling cost reductions per section drilled, will also be discussed. Performance data, supporting the discussions and processes outlined in this paper, will be presented. Background The need to improve drilling performance, as an operational cost reduction initiative, is seen as a critical industry goal. Researchers and engineers, to better understand the requirements that influence this objective, have committed time and resources to this endeavor. As a result, new drilling tools, technologies, and processes are continuously being developed to support this effort. Although project objectives have always been obvious, results have sometimes fallen short of expectations. In some instances, and even when the intended performance effects are achieved, the results have not been sustainable. PD, to achieve its intended benefits, must sustain and continuously improve on past results. To achieve this goal, the industry needs to have an open discussion that focuses on PD and its constituents. As a starter, PD needs a definition. Currently, there is ambiguity as to what it means. Some in the industry believe that the use of a new tool or technology constitutes PD. In this regard, there is the assumption that what is new or claimed to be new technology is always better. Some also believe that the use of drive tools that increase RPM or torque (PDM or turbine) in a bottomhole assembly (BHA) qualifies as PD. Others associate PD with the use of rotary steerable tools (RST). It must be stated, that even when relevant for a particular drilling operation, the mere use of a new technology or tool does not qualify as PD. The current ambiguity in PD's definition has created a process vacuum. As an enabler to reductions in operational cost, it is not enough to just identify the need for PD. This realization must be supported by processes that help identify and optimize the factors that influence PD.