Intelligent Rotary Steerable System, Coupled with an Instrumented Bit, Delivers Section Plan in Deepwater GOM Project

The challenging offshore drilling environment has increased the need for cost-effective operations to deliver accurate well placement, high borehole quality, and shoe-to-shoe drilling performance. As well construction complexity continues to develop, the need for an improved systems approach to delivering integrated performance is critical. Complex bottom hole assemblies (BHA) used in deepwater operations will include additional sensors and capabilities than in the past. These BHAs consist of multiple cutting structures (bit/reamer), gamma, resistivity, density, porosity, sonic, formation pressure testing/sampling capabilities, as well as drilling dynamics systems and onboard diagnostic sensors. Rock cutting structure design primarily relied on data capture at the surface. An instrumented sensor package within the drill bit provides dynamic measurements allowing for better understanding of BHA performance, creating a more efficient system for all drilling conditions. The addition of intelligent systems that monitor and control these complex BHAs, makes it possible to implement autonomous steering of directional drilling assemblies in the offshore environment. In the Deepwater Gulf of Mexico (GOM), this case study documents the introduction of a new automated drilling service and Intelligent Rotary Steerable System (iRSS) with an instrumented bit. Utilizing these complex BHAs, the system can provide real-time (RT) steering decisions automatically given the downhole tool configuration, planned well path, and RT sensor information received. The 6-3/4-inch nominal diameter system, coupled with the instrumented bit, successfully completed the first 5,400-foot (1,650m) section while enlarging the 8-1/2-inch (216mm) borehole to 9-7/8 inches (250mm). The system delivered a high-quality wellbore with low tortuosity and minimal vibration, while keeping to the planned well path. The system achieved all performance objectives and captured dynamic drilling responses for use in an additional applications. This fast sampling iRSS maintains continuous and faster steering control at high rates of penetration (ROP) providing accurate well path directional control. The system-matched polycrystalline diamond (PDC) bit is engineered to deliver greater side cutting efficiency with enhanced cutting structure improving the iRSS performance. Included within the bit is an instrumentation package that tracks drilling dynamics at the bit. The bit dynamics data is then used to improve bit designs and optimize drilling parameters.

Autonomous Directional Drilling Planning and Execution Using an Industry 4.0 Platform

Today, directional drilling is considered a mix between art and science only performed by experts in the field. In this paper, we present an autonomous directional drilling framework using an industry 4.0 platform that is built on intelligent planning and execution capabilities and is supported by surface and downhole automation technologies to achieve consistently performing directional drilling operations accessible for easy remote operations. Intelligent planning builds on standard planning activities that are needed for directional drilling applications and advances them with rich data pipelines that feed predictive and prescriptive machine-learning (ML) models; this enables more accurate BHA tendencies, operating parameters, and trajectory plans that ultimately reduce executional risk and uncertainty. Intelligent execution provides technologies that facilitate decision-making activities, whether they be from the wellsite or town, by leveraging the digital-drilling program that is generated from the intelligent planning activities. The program connects planning expectations, real-time execution data from the surface and downhole equipment, and generates insights from data analytics, physics-based simulations, and offset analysis to achieve consistent directional drilling performance that is transparent to all stakeholders. This new framework enables a self-steering BHA for directional drilling operations. The workflow involves an automated evaluation of the current bit position with respect to the initial plan, automated evaluation of the maximum dogleg capability of the BHA, and the capability to examine the health of the BHA tools and, if needed, an automated re-planning of an optimized working plan. This is accomplished on a system level with interdependencies on the different elements that make up the complete workflow. This new autonomous directional drilling framework will minimize operational risk and cost-per-foot drilled; maximize performance, procedural adherence, and establish consistent results across fields, rigs, and trajectories while enabling modern remote operations.

Unconventional Engineering Toward Efficient Geosteering and Well Placement - Logging-While-Drilling in an Oil-Based Mud Environment

This paper presents a success story of deploying new technology to improve geosteering operations in an unconventional horizontal well. A new-generation logging-while-drilling (LWD) imaging tool, that provides high resolution resistivity and ultrasonic images in an oil-based mud environment, was tested while drilling a long lateral section of an unconventional horizontal well. In addition to improving the geosteering operations, this tool has proven the ability to eliminate the wireline image log requirements (resistivity and ultrasonic), hence reducing rig time significantly. The LWD bottomhole-assembly (BHA) included the following components: gamma ray (GR), density, neutron, resistivity, sonic, density imager, and the newly deployed dual imager (resistivity and ultrasonic). The dual imager component adds an additional 15-ft sub to the drilling BHA, which includes four ultrasonic sensors orthogonal to each other, and two electromagnetic sensors diametrically opposite to each other (reference figure 1). This new technology was deployed in an unconventional horizontal well to help geosteer the well in the intended zone, which led to an improvement in well placement, enhanced the evaluation of the lateral facies distribution, and allowed better identification of natural fractures. The dual images provided the necessary information for interpreting geological features, drilling induced features, and other sedimentological features, thus enhancing the multistage hydraulic fracturing stimulation design. In addition, an ultrasonic caliper was acquired while drilling the curve and lateral section, providing a full-coverage image of the borehole walls and cross-sectional borehole size. The unique BHA was designed to fulfill all the directional drilling, formation evaluation and geosteering requirements. A dynamic simulation was done to confirm the required number of stabilizers, and their respective locations within the BHA, to reduce shock and vibration, borehole tortuosity and drilling related issues, thereby improving over-all performance. Real-time drilling monitoring included torque and drag trending, back-reaming practices and buckling avoidance calculations, which were implemented to support geosteering, and for providing a smooth wellbore for subsequent wireline and completion operations run in this well. A new generation dual-image oil-based mud environment LWD tool was successfully deployed to show the multifaceted benefits of enhanced geo-steering/well placement, formation evaluation, and hydraulic fracturing design in an unconventional horizontal well. Complexities in the multifunctioning nature of the BHA were strategically optimized to support all requirements without introducing any significant risk in operation.

New Generation of Ultra-High Definition Directional Propagation Resistivity for Real Time Reservoir Characterization and Geosteering-While-Drilling

Over the last two decades, the continuing integration of distance-to-boundary logging while drilling (LWD) workflows with the directional drilling processes, has dramatically improved geosteering of deviated and horizontal wells. However, the interpretation of underlying propagation azimuthal electromagnetic measurements has remained challenging in complex thin and multi-layered geologies. Recent technology advancements in LWD electromagnetic propagation resistivity coupled with significant software enhancements provide an opportunity for improving the formation evaluation to reduce wellbore position uncertainty, accurately detecting physical parameters such as layer resistivity and anisotropy, formation dip and azimuth. A newly developed multilayer mapping-while-drilling service with full azimuthal sensitivity is introduced for use in geosteering and formation evaluation while drilling applications. The tool offers the industry's first combination of axial, tilted and transverse antennas to produce a complete measurement set to enable the interpretation of complex and anisotropic formation. Advanced application algorithms are used to calculate a high-definition map of the formation providing horizontal and vertical resistivity (anisotropy), as well as dipping angle and azimuth. Furthermore, the tool can provide deep resistivity borehole images while drilling in real time. The new measurement set, more comprehensive than any other directional propagation resistivity tool in the industry, is discussed in detail. The measurements, combined with a new deterministic inversion, enable reconstruction of the resistivity of up to eight formation layers, and significantly outperforms existing directional propagation resistivity services. The new measurements and data processing workflow are demonstrated with several synthetic and field data. Examples show that this newly developed tool can provide a reliable two-in-one service: geosteering and advanced formation evaluation.

The Crustal Stress Field of Germany - A Refined Prediction

Information about the absolute stress state in the upper crust plays a crucial role in the planning and execution of e.g., directional drilling, stimulation and exploitation of geothermal and hydrocarbon reservoirs. Since many of these applications are related to sediments, we present a refined geomechanical-numerical model for Germany with focus on sedimentary basins, able to predict the complete 3D stress tensor. The lateral resolution of the model is 2.5 km, the vertical resolution about 250 m. Our model contains 22 units with focus on the sedimentary layers parameterized with individual rock properties. The model results show an overall good fit with magnitude data of the minimum (Shmin) and maximum horizontal stress (SHmax) that are used for the model calibration. The mean of the absolute stress differences between these calibration data and the model results is 4.6 MPa for Shmin and 6.4 MPa for SHmax. In addition, our predicted stress field shows good agreement to several supplementary in situ data from the North German Basin, the Upper Rhine Graben and the Molasse Basin.

Drilling Automation – Benefits of the New Drilling Model

A pilot program for automated directional drilling was implemented as a part of the roll out plan in Norway to drill three dimensional wells in an automated mode, where steering commands were carried out automatically by the automation platform. The rollout plan also targeted the use of remote operations to allow personnel to be relocated from the rig location into remote drilling centers. The goal of the program was to optimize the directional drilling performance by assessing the benefits of automation using the latest rotary steerable system technologies and machine learning smart algorithms to predict and manipulated the BHA performance, as well as the ability to predict the best drilling parameters for hole cleaning. The automation was implemented on three different rigs and the data was compared with the drilling performance from the last two years, with three dimensional wells drilled in the conventional method. The main benefits between drilling wells in the conventional method versus drilling wells with the new drilling automation model include the following. Reduce the overall cost per meter – Improve the rate of penetration – Improve running casings Consistence process adherence – Reduce human errors – Reduce POB without sacrificing lost of technical experience Optimize workforce resources – Allows continuity of service (COVID-19 restrictions) Drilling automation can drill smoother wells by reducing the friction factors and tortuosity. This is translated in direct cost savings per meter and reduction in the overall well delivery time, with the advantage of performing the execution and monitoring of the well performance remotely. This new drilling model open the door of new opportunities, especially for the challenges where the work force resources, and drilling performance is a priority for the operations.

New Intelligent Push-the-Bit Rotary Steerable System Helped Reducing Well Time and Maximized Directional Drilling Performance, Abu Dhabi, UAE

To meet the current oil and gas market challenges, there is an industry need to optimize cost by safely drilling longer horizontal wells to maximize well productivity. Drilling challenges include the highly deviated trajectory that starts from the surface sections and wellhead, the high DogLeg Sevirity (DLS) profile with collision risks, and the thin complex geological structures, especially in new unconventional fields where numerous geological and geomechanical uncertainties are present. To mitigate for those challenges, reviewing the existing drilling techniques and technologies is necessary. To compete in the current Hi-Tech and Automation era, the main challenges for directional drilling service providers are to reduce well time, place wells accurately, and improve reliability, reducing repair and maintenance costs and helping the customer reduce time and costs for the overall project. Offset wells analysis and risk assessments allowed identifying the main challenges and problems during directional drilling phases, which were highlighted and summarized. As a proposed solution, the new generation of intelligent fully rotating high dogleg push-the-bit rotary steerable system has been implemented in the UAE onshore oil and gas fields to improve the directional drilling control and the performance. This implementation reduced the Non-Productive time (NPT) related to the human errors as the fully automation capabilities were being utilized. The new rotary steerable system has the highest mechanical specs in the market including self-diagnosis and self-prognosis through digital electronics and sophisticated algorithms that monitor equipment health in real-time and allow for managing the tool remotely. As a result, the new intelligent RSS was implemented in all possible complex wellbore conditions, such as wells with high DLS profile, drilling vertical, curve, and lateral sections in a single trip with high mud weight and high solid contents. Automation cruise control gave the opportunity to eliminate any well profile issues and maintain the aggressive drilling parameters. Using the Precise Near-bit Inclination and Azimuth and the At-Bit Gamma real-time data and high-frequency tool face measurements in the landing intervals where required for precise positional control to enable entering the reservoir in the correct location and with the correct attitude helping the customer's Geology and Geophysics department to place wells accurately while maintaining a high on bottom ROP.

First Application of Hybrid Bit Technology to Optimize Drilling Through S Shape Directional Section with High Chert Content in UAE Land Operations

This paper highlights the solution, execution, and evaluation of the first 12.25″ application of hybrid bit on rotary steerable system in S-Shape directional application to drill interbedded formations with up to 25 % chert content in UAE land operations. The main challenge that the solution overcame is to drill through the hard chert layers while avoiding trips due to PDC bit damage nor drilling hour's limitation of TCI bit while improving the overall ROP and achieving the directional requirement. The solution package has demonstrated a superior ROP over rollercone bits, as well as improved PDC cutter durability and lower reactive torque leading to better steerability and stability which will be detailed in this paper. A significant contributor to such success was utilizing a new hybrid bit technology which incorporates the dual cutting mechanisms of both polycrystalline Diamond Compact (PDC) and rollercone bits. This allows a more efficient drilling by bringing the durability of the crushing action of rollercone to drill through hard interbedded lithology and the effectiveness of the shearing action of PDC cutters to improve ROP without sacrificing the toughness of the cutting structure edge. The proposed solution in combined with continues proportional rotary steering system managed to drill 4,670 ft through heterogeneous formation with chert nodules, with an average ROP of 38.29 ft\hr improving ROP by 15% and eliminating extra trips of utilizing roller cone bits to be able to drill though the chert nodules and avoid the PDC bit damage. Leading reduction in cost per foot by 35 %. Additionally, the hybrid bit exceed the expectation achieving 878 thousand of revolutions, with effective bearing and with the drilling cutting structure in a very good condition. Furthermore, the directional objectives were met with high quality directional drilling avoiding wellbore tortuosity. Such success was established through application analysis, specific formations drilling roadmaps and optimized drilling parameters in order to improve the overall run efficiency. The combination of roller cone and PDC elements in a hybrid bit designed to deliver better efficiency and torque stability significantly increased performance drilling the section in one single run, proven that heterogeneous formations can be drill.