To efficiently develop reserves in the Norwegian North Sea, the operator must drill a challenging 12¼" directional borehole through a Chalk formation with high stick-slip potential. In Gaupe North, a negative vertical section was required in the initial kickoff to properly line up the well path before entering the reservoir target. The reservoir is comprised of channel/sheet sandstones interbedded with shale sequences with different pressure regimes and nearby reservoir depletion issues. The 8½" wellbore must penetrate an unstable organic shale just above the reservoir, infamous for causing hole stability problems and stuck pipe events. The regulatory agency requires this shale to be drilled in an 8½" section, requiring long exposure time, which increases risk for hole problems when running the production liner. The objective was to efficiently drill these trouble-zones and deliver two horizontal producers in a cost effective manner using an integrated engineering solution.To achieve the objective, a sophisticated multidisciplinary approach was employed including: bit/BHA offset analysis to reduce stick-slip in the chalk; BHA/RSS and drilling fluids modeling/planning; and drilling parameter plots to identify optimum RPM/WOB. Also, a real-time parameter analysis system was deployed to optimize ROP without compromising hole cleaning or well integrity.The synergy provided by a fully integrated service provider increased drilling performance and was a major contributor to the success of the Gaupe wells performance. Well 6/3-A-1H broke the previous Rushmore index for subsea development wells in the region and set a Norwegian record for wells in this class. Both wells (15/12-E-1H & 6/3-A-1H) achieved positive P10 curves and saved a total of 18 days vs AFE. Compared to an analogous UK North Sea field, significant increases in ROP were achieved resulting in the wells being drilled 20+ days faster than benchmark. The average increases in ROP for the two Gaupe wells were approximately 146%, 47% and 148% in the 17½", 12¼" and 8½" sections respectively.

In the world of drilling, the drill bit dull condition contains our best forensic evidence of the drilling assembly's interaction with the formation. Dull grading forensics is the first place to look to identify drilling dysfunction yet commonly overlooked or misunderstood by operators. The drill bit dull condition can be leveraged to learn about the formation, drilling dynamics and drilling practices (Watson et. al. 2022). The IADC bit dull grading classification system received its most recent revision in 1992 and currently consists of an average inner and outer dull grade severity, rated from 0 – 8 with a major and other dull characteristic along with a reason pulled. These grades can be used to make critical operational and bit design decisions to overcome drilling challenges thereby improving performance and allowing drilling teams to drill consistently further and faster. The oil and gas industry is becoming more reliant on digitally enabled applications to improve performance through big data, machine learning and automation, but at the time of this paper, the critical IADC dull grading system has remained the same. It is still a crude and subjective characterization of the complex drill bit dull condition. A key challenge with the current classification system and industry standard grading technique is that it is highly dependent on the person grading the bit. Personal subjectivity and lack of training can result in key forensic evidence being overlooked that otherwise could have aided in understanding the root cause of drilling dysfunction. A cross disciplinary committee of subject matter experts (SME's) from operators, drill bit providers, cutter manufacturers, and digital solution providers have convened to define and introduce a new standard dull grading system as replacement for the current outdated IADC dull grading. The new dull grading system will allow for an objective cutter-by-cutter dull grading to be stored with relevant drilling data with reduced subjectivity and enhanced accuracy. With recent advancements in mobile phone hardware and applications, a solution was developed that delivers high quality, cutter-by-cutter dull grading automatically and connecting with drilling meta data from a drilling records database containing over 1.8 million well records with over 5 million bottom-hole assembly (BHA) runs. It leverages videos with machine learning combined with an algorithm to deliver cutter specific, major dull characteristics of a scanned bit. This high quality photographic digital dull information is incorporated into workflows allowing for rapid improvement in cutting structure and cutter development lifecycle timelines leading to rapid improvements in drilling performance for operators.

Hole Enlargement While Drilling (HEWD) using a concentric underreamer is a widely used technique for efficient wellbore construction. Most underreamers are fitted with lock-out systems to provide a means of drilling out the shoe-track with the cutters close before enlarging the borehole below casing. Several vendors also provide a system to lock the tool closed after reaching total depth (TD) to enable full flow while pulling out of the hole for best possible wellbore cleaning. However, most available underreamers cannot be reactivated after deactivation. Another limiting factor is that the tools must be placed on top of the Bottom Hole Assembly (BHA) due to the ball drop activation method. To solve the problem, a new system has been developed that makes it possible to perform multiple activation/deactivation of the underreamer. The most obvious advantages are infinite open/close cycles for selective underreaming and the more flexible placement opportunities within the BHA due to the activation method. Other advantages are time saving through the elimination of several runs, shorter activation time and higher flow rate capabilities. Several successful tests in realistic drilling environments were performed prior to starting the field testing program. Through the field testing stage the system has performed as planned under normal drilling conditions and has a significant cost saving potential for the operator. The authors will discuss the application challenges, benefits, features and engineering efforts including field testing, that led to a commercial Ream on Demand (ROD) system.

Developing reserves offshore East Malaysia, especially in deep water, often requires the operator to drill -through formations that consists of compact carbonate with high unconfined compressive strength (UCS). Efficiently penetrating these carbonate formations with conventional PDC bits has been challenging; typically, when a bit encounters this formation, a high vibration level is induced that leads to impact cutter damage, forcing a round trip for a new bit and causing nonproductive time (NPT) and additional cost for a new bit. Consequently, the cost impact is more severe to the operator, especially in deep water environments. Traditionally, an operator has used four- and five-bladed PDC bits to drill this formation because this configuration had set a benchmark in this field compared with roller cone bits. However, a recent engineering analysis on a recently drilled offset well showed that a minimum of two PDC bits are required to reach the section total depth (TD). On the first run, the bit was pulled out of hole (POOH) due to slow ROP 6.2 m/h) and received a poor dull grade (6-7-HC-ROP). Although the second PDC bit produced slightly higher ROP compared with the first bit, it was POOH with broken cutters. A research initiative was launched to investigate new types of cutting elements. The project was successful and yielded an innovative conical-shaped polycrystalline diamond element (CDE). This element has twice the diamond thickness of conventional PDC cutters, resulting in higher impact strength and more resistance toward abrasive wear by approximately 25%. A new bit type was designed with the CDEs strategically placed across the bit face from gauge to the bit center utilizing FEA-based modeling system. The placement of CDEs is mainly to support and protect the conventional PDC cutters from impact damage and to strengthen the overall cutting structure. The 8½-in CDE bit was run and drilled the entire 8½-in hole section through the hard carbonate formation to TD at a significantly higher ROP compared with the offset well. Although the CDE bit was POOH due to downhole tool failure and graded 1-2-BT-DTF, the same bit was rerun and successfully completed the hole section in good condition and dull graded as 1-3-BT-TD. Compared with the offset well that required two conventional PDCs to reach TD, the CDE bit delivered more drilled interval at a higher ROP while providing a smooth, high-quality wellbore, enabling casing to be set on the first attempt. Also, the dynamic response predicted by the modeling system matched the bit, BHA, and drill string vibration profile recorded during the actual field run. Improvement in drilling performance for this run has saved the operator 15 hours for the same drilling interval.

Utilizing big drilling data requires an innovative approach. The service company’s drill bits business is largely based upon an in-house drilling record system (DRS) that captures global bit record performance data. The DRS contains over 1.8 million wells drilled worldwide since 1980 with nearly 5.4 million total BHA runs from over 100 countries. In the last 10 years alone, over 1.4 million bit runs drilling over 2.8 billion ft of formation have been recorded. To utilize this vast amount of data for drill bit performance evaluation, analysis, and monitoring, the innovative approach described in this paper was developed and implemented. Traditionally, the performance of a drill bit run–often measured in terms of drilled footage and ROP–has been evaluated versus similar offset runs. Offset runs are chosen in various ways, but are typically done manually by bit engineers, meaning that offset run selection is subjective based on personal experience and bias. Furthermore, people often only evaluate the performance of test bit designs. Instead, we wanted to analyze and monitor the performance of all drill bit runs. To alleviate these biases and enable a wider breadth of considered runs, an objective offset run selection workflow was developed and implemented within DRS. Offset runs are selected based on a sophisticated filtering and scoring routine that considers many characteristics such as geographic location, time, wellbore and drilling system design, along with lithology. As new data enters DRS continuously, this workflow runs on a regular basis using an automated pipeline. The performance evaluation results of the automated offset selection workflow are available to all data analysts (engineers and salespeople) both inside DRS and extensible applications to aid in performance monitoring and new product development target-setting. Product performance is now objectively evaluated at-scale across geographies and always utilizing apples-to-apples comparisons. The workflow has proven itself quite useful and delivered business value already but also exemplifies the need for both enhanced data quality and improved bit record data capture rate. These are ongoing efforts to further enhance and improve this workflow. Automated workflows like this one can help our industry by eliminating repetitive biased tasks and allowing people to focus on more creative processes leveraging objective data. Developing new drill bit designs, material selections, or component selections to overcome new challenges are creative processes which contribute to increased drilling performance and lower costs for the industry.