Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
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 The effectiveness and impact of internal audit procedures implemented within an Operator’'s Well Engineering organization is described and how it ensures quality and integrity of the performance in the company’'s operating units. The work is based on four years of internal operations audit data where the results of operations audits have been analysed to identify trends in the levels of compliance and the quality of the technical work carried out in the different operations group. It is explained how compliance with policies, procedures and standards is set and monitored within the Company and also show the effect of internal audit activities on performance. One of the outcomes of the audit process is the continuous refinement of the audit tools themselves. The audit results also highlight the need to review and refine the well delivery process itself and show correlation between audit results and operational performance. The results provide useful metrics and give an indication of the state of the health of the well engineering organisation.
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 Oil and gas project development in the North Sea is known for large discoveries, requiring the need for highly complex, capital intensive infrastructure, which can take decades to complete. Recognizing that such discoveries were becoming less common, a faster and less capital intensive approach was needed to develop smaller fields. The idea was to target fields close to existing infrastructure that could tie back to current installations and only require a seabed template. Historically, these types of projects would take the company over five years to complete. A dedicated team was established to plan these smaller projects, appropriately called “Fast Track” projects, and was challenged with cutting development time in half. The Fast Track team used lean principles to analyze project lead times and target improvement opportunities. Lean is a methodology made famous in automotive manufacturing, which seeks to eliminate time wasting activities and reduce overall lead time (De Wardt 1994). The primary lean technique employed by the team was value stream mapping. First, the team mapped out the entire project development process, from discovery to production, and identified all the key steps in the process. Second, the team estimated the time it takes to perform each major step in the process and calculated the total lead time for project development. Finally, the team quantified all the sources of delays and developed opportunities for improvement. These opportunities were then ranked based on the potential time and cost savings. With the prioritized opportunities, an improvement road map was developed to steer the team in the right direction. The improvement road map contained a four-pronged approach to cut project development times in half: Standardization Collaboration Streamlined processes Change management Standardization involved developing standard subsea templates, well designs, and completions equipment to cut the time to develop solutions. Collaboration involved integrating the operator and the service company and making use of teams in different time zones to accelerate well design and planning. Streamlined processes focused on combining decision gates in capital projects and working the well construction process in parallel to the project development process to reduce planning time. Finally, change management involved establishing a continuous improvement process, a system to implement ideas and engrain them into the organization, and a common set of key performance indicators to align different stakeholders and drive execution results. Implementation of these improvement opportunities led to a reduction of over two years in the time needed to complete the development projects: from 5.3 years to an average of three years.
- North America > United States > Texas (0.29)
- North America > United States > Montana > Roosevelt County (0.24)
- Europe > United Kingdom > North Sea (0.24)
- (3 more...)
Look Ahead Team MXS: Transforming Knowledge in Successful Operations
Rodríguez, E.. (Schlumberger) | Jiménez, A.. (Schlumberger) | Angel, J.. (Schlumberger) | Bedino, H.. (Schlumberger) | Scagliarini, S.. (Schlumberger) | Salinas, N.. (Schlumberger) | Valdiviezo, F.. (Schlumberger) | Mendoza, P.. (Schlumberger)
Abstract This paper describes how the creation of an innovative multidisciplinary team - the Look Ahead Team (LHT) - together with ad hoc new built processes and protocols, have greatly helped minimizing both the geological and drilling risks and their impact in the very complex wells currently being drilled in the Mesozoico, Exploration and Alliance projects in Southern Mexico (MXS). Also, it explains how the integration of different knowledge domains coupled with detailed technical scrutiny, subsurface visualization, modeling and simulation, thorough multilayers risk assessments, risk management techniques, real time data acquisition and continuous application of lessons learnt, have been delivering substantial savings to the drilling operations. Wells can be classified as deep HP/HT and/or LP/HT wells. The objective of the LHT is to visualize and analyze drilling related risks, to generate alerts and recommendations before a new hole section is commenced, so that undesirable and detrimental subsurface events are anticipated and prevented or minimized. Drilling engineering, geology, geophysics, geomechanics and well placement are all represented in and form an integral part of the LHT. For each new well to be drilled, the geosciences' domain experts perform an integrated subsurface interpretation considering all current information available, offset wells and real time data. The analysis performed is twofold: a forecast drilling scenario (well trajectory and placement) which is optimized based on the calibration attained through the iteration with existing (offset) wells using sophisticated modelling and newly created work protocols that allow effective multidisciplinary workflows, subsurface assessment and detailed risk analysis by hole section. The main outcome of the analysis is to deliver a predictive ‘look ahead’ report which contains all risks identified at least 200 m ahead of the bit together with the risk analysis matrix and the corresponding prevention and mitigation plan. Also during the program execution, the LHT provides technical support to the engineering and operations teams anticipating the next action based on risk projection re-assessment using real data streaming. The Look Ahead Team's newly implemented processes/workflows and innovative analysis methodologies, have been tested on 21 development wells and 3 exploratory wells for a total of 72 hole sections. In just one year from its foundation, unforeseen drilling events due to geological uncertainty were reduced by 90% achieving 10MMUSD worth of savings.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (0.94)
- Geophysics > Borehole Geophysics (0.46)
- Geophysics > Seismic Surveying (0.30)
Abstract Hole opening with bit and reamer, continues to receive attention in the drilling industry (Meyer-Heye, et al, 2010), due to the operation's numerous advantages. In comparison to conventional (single diameter) drilling, hole opening bottom hole assemblies (BHAs), are more complicated, in terms of their design and operation. The presence of two cutting tools, bit and reamer, in hole opening BHAs present additional drilling dynamics challenges (Heisig, et al, 1998). As a result of these issues, hole opening applications are commonly plagued by the following shortfalls – shorter BHA runs, excessive vibrations (Fear, et al, 1997), downhole tool failures, poor borehole quality, lower rate of penetration (ROP), and compromised directional performance (Mensa-Wilmot, et al 2014). These challenges, which have drastic negative effects on operational costs, amplify in harsh drilling environments (Mensa-Wilmot, et al, 2001). The above issues must be addressed, to ensure cost trend reversals in hole opening applications. This objective requires solutions that focus on the challenges at their sources of initiation. Most important the solutions must ensure consistent and continuous gains in performance. This paper will present new concepts in hole opening, with regards to project analysis, planning, and execution. The discussions will identify and resolve specific hole opening challenges, with emphasis on harsh environment drilling applications. Field cases with supporting data, highlighting the impact of new solutions on project cost reductions, will also be presented.
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 Managers crave greater confidence in well construction costs, from the inception of a cost estimate for investment decisions, through cost estimation for budgeting, to cost tracking and control during well construction, and finally, for validity of performance tracking and benchmarking. Shortfalls in well cost estimation and control are due to three main sources: lack of defined processes, lack of discipline, and reliance on outdated or poor methodologies. This technical paper describes advanced methodologies for effective well cost management and documents their benefits to decision-makers and the industry. These include processes from the construction industry for cost tracking / control, best practices for estimating using probabilistic methods and leading to a process that can be applied for any well complexity utilizing modern methodologies. The technical content contributes directly to improved decision making by managers for investment in wells, improved planning for better decision making on choices for well design and drilling / completion operations including applications of various technologies, improved control of costs, and improved confidence that performance tracking and benchmarking are based on valid measures.
- Management > Strategic Planning and Management (1.00)
- Management > Risk Management and Decision-Making (1.00)
- Management > Asset and Portfolio Management > Capital budgeting and project selection (1.00)
- Facilities Design, Construction and Operation > Facilities and Construction Project Management > Cost estimation and control (1.00)
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.
Summary BP and Maersk Drilling entered into a unique collaborative arrangement in early 2013 to develop the design for a deepwater drilling rig that is specifically aimed at conducting operations on wells with greater than 15,000 psi pressures. This paper describes how this collaborative effort was conducted. Operator and contractor each contributed expertise and information to the project and defined a joint vision of transforming how functional requirements are set and how the design of this rig would be developed. A set of relationship principles was agreed and a joint project team was formed in Houston with engineering support from contrator's technical organization in Copenhagen. An executive committee, with senior leadership from each organization, was established to provide guidance, challenge and governance. To start the design process, workflow during the well construction process was layered on top of the foundational requirements of operator's prospect inventory. Starting with a cleaner sheet of paper, the integrated team's conversations focused on inherently safer design and improving operability, efficiency, maintainability and reliability. The initial focus was on innovation and possibilities before driving toward agreement on the functional specification and rig design. The team strove to address challenges faced in the deepwater drilling industry today, at the same time continually testing their ideas for benefit. After more definition work, the opportunities were run through a detailed evaluation model to inform selection of design features and potential equipment suppliers. Major equipment suppliers and operator service companies have assisted with the development of rig functional requirements and the shipyard specification. Operator and contractor contributed their learning from previous rig builds, intakes and operation including five and ten year re-certifications into the design. Supplier selection for long lead technology development and qualification of equipment commenced in 2013 and is expected to culminate with a yard selection in 2015. As a result of this collaboration, operator and contractor better understand the needs and drivers of each other's business and have leveraged this knowledge into a more effective working relationship. Significant work remains to construct the rig and deliver it into operation. However, there is a strong belief this next generation deepwater drilling rig will provide enhanced capability, performance and value to both operator and contractor.
- North America > United States (0.28)
- Europe > Denmark > Capital Region > Copenhagen (0.25)
- North America > United States > Mississippi > Houston Field (0.89)
- North America > United States > Louisiana > Copenhagen Field (0.89)
- Well Drilling > Drilling Equipment (1.00)
- Management > Strategic Planning and Management > Project management (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (1.00)
- Management > Professionalism, Training, and Education > Communities of practice (0.94)