No abstract

The purpose of this paper is to demonstrate the power and business benefits of leveraging online analytical processing (OLAP) cubes in the utilization of high-level data analytics and data dashboards from an established drilling record system (DRS). The DRS contains over 1.4 million wells, including 75,000 offshore wells drilled worldwide since 1980 with nearly 5 million total bottomhole assembly (BHA) runs from over 100 countries. Since 2009, over 1.5 million BHA runs drilling 2.6 billion feet of formation have been captured. Being able to visualize and understand the drilling data allows for increased efficiencies, reducing the days on wells for operators from deepwater to inland barge and land drilling worldwide. The development of the OLAP cubes required a multidisciplinary team consisting of software developers, business managers, domain champions, field-based engineers, and data scientists. The OLAP cubes consist of multidimensional databases built from relational and algorithmic interpretations of DRS transaction data. These algorithms are generated and developed by an iterative cycle of continuous improvement, development, and utilization of the OLAP cubes in parallel to improve the functionality and business impact for performance analysis, sales, product development, product reliability, and marketing. The data can be analyzed and visualized in the Microsoft Office suite by directly querying the DRS OLAP cubes. This also allows for dashboards to be updated in real time as data are added to DRS. OLAP cubes have been developed to analyze the performance of drill bits, motors, reamers, rotary steerable tools, and many more downhole tools. The DRS cubes assist in identifying failure causes on bits to identify high-risk intervals to better target products and parameters to reduce costly nonproductive time. Fit-for-purpose OLAP cubes have been developed to understand drilling efficiencies and strategies in multibit versus single-bit sections using variable trip speeds and field performance. Traditional business reports were made more efficient and auto-updated and dashboards were built to identify major business trends to equip business managers. This OLAP cube development has allowed for increased usage of the world's largest drilling record database and has made it easier to access and analyze the data. Ultimately, the techniques and development described in this paper help answer business questions to make better business decisions through data-driven analytics.

Schlumberger, one of the world’s leading suppliers of oilfield technology, is a measurement and data-driven company that collects massive amounts of data in the course of its daily operations. These data, diverse in nature, are collected for use in various business and technical workflows. The data can be downhole, surface, post-analysis, and support functions from manufacturing, maintenance, asset management, and finance. Analysis of this Big Data has the potential to drive a step change in operational performance across multiple dimensions. However, accomplishing this step change is not easy to accomplish because often, the data are not well structured and are scattered across individual business systems that do not communicate well with each other. Most of the analysis of these scattered data occurs on a point basis, requiring the significant involvement of various experts and complex time-consuming manipulations. The results are short lived in that they cannot be tracked in real time and the effort expended is not applicable to other data sets or problems. Increasing data volumes, data diversity, and demand from engineers to record multiple new data attributes during the product or technology life cycle further limits the benefits of such a spot analytics process, with potentially severe impacts on the business due to inadequate decision support or missed opportunities. This paper presents a developmental model and change processes, challenges faced and resolution approaches leading to digital transformation, and finally, the resulting value creation through building data visualizations and comprehensible decision-making tools. Once the initial high-value data sets and visualizations are identified, automation opportunities can be exploited. These data sets become the foundation for predictive analysis and machine learning through artificial intelligence (AI) and Internet of things (IoT) to further influence product performance and development in support of customer needs.

The Red Oak Field is located in the Arkoma Basin in Southeastern Oklahoma. The Field recently exceeded peak production levels in what was previously deemed a fully developed reservoir, through an ongoing successful infill drilling program based on the use of three-dimensional (3-D) seismic. Moreover, the redevelopment program has surpassed the 100 well mark and has delivered some high rate gas wells. The field may be characterized by its dry gas and multiple pay horizons in what has long been known to be "crooked-hole country". In situ compressive strengths range from 10,000-psia through the Pennsylvanian to 55,000-psia through the Ordovician. Much work has been done in the past to optimize air drilling operations for shallow wells; however, as deeper horizons are exploited new technologies have been implemented in order to deliver continuous improvement. Drilling improvements in recent years have included the introduction of a state-of-the-art drilling rig, further optimization of air drilling operations and the introduction of Polycrystalline Diamond Compact (PDC) bits. A down-hole vibration mitigation effort was also initiated which yielded improved bit runs and the identification of micro-tortuosity and weight transfer issues. Vibration mitigation resulted in the redesign of bottom hole assemblies (BHA) and the optimization of bent-housing steerable-motor angle settings. Rig rates have increased over time, along with the need for designer wells. Rotary Steerable Systems (RSS) were therefore implemented to address these issues. Initial attempts indicated that RSS were not able to overcome the formation tendencies in 3-D space. A detailed investigation resulted in the hypothesis whereby speeding up the RSS with a motor would provide enough side force with a push-the-bit system to overcome formation tendencies. Real-time Mechanical Specific Energy (MSE) measurements were used in conjunction with the implementation of a Powered Rotary Steerable Systems (PRSS) and revealed the fact that the full benefit of the RSS was not consistently realized (mostly due to the extreme nature of the drilling environment). As such, prototype extended-gauge PDC bits were designed in order to further reduce down-hole vibration, improve well bore quality and bit performance. The result has been sustained top quartile performance, a state drilling record and the continued growth of a mature field. Introduction Flournoy1 elaborated on the benefit of air hammer drilling in the shallow surface hole sections of wells in the Arkoma Basin. At the time of his publication optimization efforts resulted in rate of penetration (ROP) of 100-ft./hour versus the average of 25-ft./hour. Since then ROP's in excess of 200-ft./hour are not uncommon for air hammer systems. Although the surface hole sections are air drilled to this day, the primary reason is not penetration rate but rather the likelihood of mud losses with conventional mud systems. It should be noted that in recent years PDC bits run with mud systems just below surface casing routinely deliver similar performance. However, drilling with a mud system in the shallow surface section of the well has a distinct disadvantage in that severe losses of mud are likely. Unfortunately, gyroscopic surveys from surface hole sections which have been air drilled with hammers at high penetration rates have shown excessive dog legs and inclinations as high as 7-degrees in some wells. The result has at times been unpredictable drift of the well path which may not be an issue for shallow Red Oak wells but is certainly an issue for wells drilling to deeper depths. Most of the wells drilled within the last two years in the Red Oak Field required drilling from less than ideal locations atop mountains or drilling multiple target wells with tails below typical pay horizons. Improvements in seismic and geologic interpretation by the Sub-surface Technical Team resulted in designer wells (see Figure 1) with tight tolerances. The thrusted, faulted and folded nature of the formations in the basin made directional operations onerous and costly. Directional constraints coupled with the fact that air hammer drilling operations for the surface section of the wells provides very little directional control often results in directional operations beginning from an even less-desirable location. As a result ROP's in the air drilled surface section are often constrained in order to alleviate potential shallow dog legs for deeper wells.