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Collaborating Authors
Drilling Equipment
Abstract Objective/Scope The rotating control device is an integral piece of equipment for managed pressure and underbalanced drilling applications. In 2005, a joint IADC/SPE committee, collaborating with American Petroleum Institute, authored specification guidelines first published as API-16 Specification RCD (API-16 RCD). Does applying a manufacturing specification as a control for operations really minimize risk, or does it limit liability? This paper will outline the journey toward API-16 RCD certification, gaps identified between testing results and operating guidelines, and methodology applied to field performance data to bridge test data with real-life performance expectations. Method/Procedure/Process Analysis of a large laboratory test data set has been accumulated for the API-16 RCD application process. Meanwhile, a much larger data set of field performance has been accumulated over several years from live operations throughout the world. In an effort to seek continuous performance improvement, interrogating the data to determine a proper base line for performance was initiated. It became apparent that determining this base line was challenging, given the wide range of variables. However, through systematic data analytics, along with improved field data capture guidelines, normalizing these variables enabled operating data to validate performance inferences drawn from the existing lab data. Results/Observations/Conclusions Several hundred field runs were compared against more than 50 independent lab tests to determine links. Through comprehensive data analysis, along with acknowledgement of the scientific limits understanding elastomer performance over conditions and time, RCD testing in the lab is better able to predict field performance, serving as a suitable alternative to costly fit-for-purpose field simulation testing. Additionally, this methodology better guides technology improvements required to expand performance criteria. Novel/Additive Information Replicating field conditions in controlled laboratory tests requires a significant range of variables beyond RPM, temperature and pressure. For example, field failures have resulted from chemical factors such as mud compatibility at a range of temperatures, or physical factors such as drillpipe condition and rig alignment. Some in industry view fit-for-purpose testing as a solution, but this can become cost prohibitive for service providers and operators alike. This paper will document viable alternatives.
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Equipment (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- (2 more...)
Abstract Objectives/Scope Today, during the development of unconventionals and particularly in the challenging rock of the Permian Basin, a lack of knowledge about the downhole environment creates a culture of conservatism where excessive safety margins need to be applied to prevent damage to the rig equipment, drill bits, and sensitive drilling tools. Due to varying crew capabilities, inconsistent performance is the norm and lessons learned are poorly implemented on each rig and across the fleet. This paper discusses the implementation and the performance impact of drilling with a fully integrated automation system. That system combines high-speed surface and downhole data, a process controller, and a modern 1500-HP AC land rig. This is the first time in the world that this combination has been utilized in drilling. Methods, Procedures, Process This paper discusses the equipment involved in a fully integrated drilling automation system. It will discuss the various impacts on performance of components of the system and the additional benefits of a fully integrated system. The process controller can derive its setpoints from surface data, high-speed downhole data, and a comprehensive model, using accurate information that reflects the true downhole environment and allows the system to be run without conservative safety margins. Throughout the drilling process, the drilling applications and software interface with the control system, providing real-time downhole dynamics data such as weight on bit (WOB), toolface control, wellbore stability, cuttings monitoring, and performance steering. When the well was completed, the lessons learned were automatically captured and the new optimized well program was uploaded to the system for the next well in the sequence, where it repeated the improved process. Through integrated automation, the rig drilled close to its technical limit, applying proven drilling processes for consistent, repeatable performance. 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 fully integrated automation system allowed the driller and the customer representatives to maximize the performance of the rig without compromising safety or the reliability of the equipment. The integrated system significantly reduced the spread of spud-to-total-depth (TD) times and learnings were efficiently and consistently implemented, delivering continuous improvement. Novel/Additive Information In the challenging economic environment that our industry currently faces the implementation of game-changing technology as described above has a huge potential impact on reducing the lifting costs of oil in unconventional plays worldwide. Integrated automation provides a huge upgrade in performance for the current fleet of high-end AC rigs. Success of this project was also achieved by having a business model where customer, contractor, and equipment provider were all aligned and shared in the performance gains.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (0.71)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)
- Well Drilling > Drilling Equipment (1.00)
- Well Drilling > Drilling Automation (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (0.89)
- (4 more...)
- Information Technology > Software Engineering (1.00)
- Information Technology > Software (1.00)
- Information Technology > Architecture > Real Time Systems (0.50)
Mitigating Drilling Dysfunctions and Enhancing Performance with Self-Adjusting Bit Technology: Analytical and Experimental Case Studies
Jain, Jayesh R. (Baker Hughes Incorporated) | Ricks, Gregory (Baker Hughes Incorporated) | Ledgerwood, L. W. (Baker Hughes Incorporated) | Phillips, Anthony (Baker Hughes Incorporated)
Abstract Mitigating drilling vibrations and pushing the upper limit of performance while drilling long sections in a single bit run remains a challenge for fixed polycrystalline-diamond-compact (PDC) bits. Recently, new self-adjusting depth-of-cut (DOC) control technology was introduced to help overcome these challenges. This paper presents further details of how the technology works in a wide range of drilling conditions and demonstrates performance benefits in research wells. Building on the conceptual illustration presented in SPE-178815, time domain modeling is performed to study influence of the self-adjusting mechanism on the drilling system response. The results of simulations are corroborated with full-scale testing in the laboratory. Additionally, field testing is conducted in research wells to demonstrate the ability of the technology to reduce drilling vibrations and push the performance envelop. Scenarios such as torsional stick/slip vibrations, weight-on-bit (WOB) transfer issues, improper starting procedures, and heave excitation in offshore wells are considered on conventional rotary as well as motor bottom-hole assemblies. The technology provides the bit with the ability to continuously adjust its DOC control characteristics to suit the drilling environment: it engages DOC control when encountering vibrations to mitigate them and disengages when drilling smoothly to deliver high rate of penetration (ROP). Significant benefits are observed when drilling with self-adjusting PDC bits in a variety of operating conditions. In addition to mitigation of stick/slip vibrations, reduction in cutter overload is observed when sudden loading is encountered, such as during weight stack-up events or re-starting after connections. When subjected to oscillating WOB, which mimics heave excitation, downhole measurements of vibrations show self-adjusting bits exhibiting reduced levels of torsional vibrations compared to fixed PDC bits. The testing also shows promise in reducing cutter wear and extending bit life. The paper enhances the understanding of how the novel self-adjusting DOC control technology works in realistic drilling conditions. The simulation and testing results demonstrate applicability of the technology in a variety of drilling dysfunctions experienced in the field.
- North America > United States (0.46)
- Europe > Netherlands (0.28)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Well Drilling > Drillstring Design > Drillstring dynamics (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Equipment (1.00)
- Well Drilling > Drill Bits > Bit design (1.00)
Abstract This paper describes a collaborative effort between an operator, a drilling contractor and a service company to introduce specific aspects of automated technology to a major drilling operation. The application of automated technologies to the process of well construction is emerging as a key lever to improve the overall efficiency of drilling performance. Though not yet mainstream, several recent applications have demonstrated that the technology maturity is no longer the limiting factor in accelerating the uptake and realizing the benefits that automation can bring to drilling. A major challenge that has emerged in implementing drilling automation is the fragmented and often non-symbiotic business model that exists between key stakeholders. Additionally challenges exist around the lack of inter-operability between various parties' specific hardware and software. This issue extends to the multiple data streams involved, the data's robustness and how to integrate these adequately to drive automated processes. As with any technology introduction, new complications appear and this is no different for implementing automation technologies in drilling. Among the many new challenges are the increased cyber-security risks introduced by exposing the drilling control system to external networks, as well as the human factors challenges associated with changing well established workflows on the rig floor. The sum of these is to manifest itself in improved drilling performance without compromising on the safe operation of the rig. In this particular case, the discussion centers on the application of automation to drilling parameter control as it relates to improving the rate of penetration in hard rock drilling environments. Successful implementation of automation technologies in drilling is a significantly complex endeavor, and the measures of success may not be immediately apparent. Instead, a vision that encapsulates a longer term, strategic view on the potential benefits that automation can bring to well construction is required, with shorter term tactical milestones being well defined, and a systematic plan engaged to achieve them. The paper explores how the above issues were managed over a testing and implementation period of approximately three years covering the transition from an advisory mode system to an automated one. Automated process control applications on drilling rigs will continue to increase in both the number of deployments as well as the breadth of functions covered. The project described illustrates one approach that is unique to date in terms of the technology and the degree of collaboration employed by the stakeholders to successfully deliver the objectives. Early adoption initiatives as discussed here are essential for the technology to evolve. They provide the industry with a series of lessons that help to sustain and direct the future of drilling automation and its role in enhancing well construction capabilities.
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Equipment (1.00)
- Well Drilling > Drilling Automation (1.00)
- (4 more...)
Abstract Severe vibrations in drilling systems are one of the main limiting factors for an efficient drilling operation. An adjustment of drilling parameters is necessary to avoid the negative impact of vibrations on reliability, measurement quality, and rate of penetration. The time to drill a well is therefore directly or indirectly affected if vibrations are not properly managed; measurements must be repeated, damaged tools can lead to additional tripping time, and rate of penetration is limited by reduced power that is delivered to the bit and restrictions of operational parameters. Complex well trajectories, a difficult drilling environment, and the extended-reach of wells are additional challenges for drilling operations. The use of a mud motor in the bottom-hole assembly (BHA) is one option to supply power directly to the bit. However, if the mud motor is not properly managed, its operation can lead to lateral vibrations. BHA design and optimization of operational parameters are options to mitigate lateral vibrations. A basic understanding of mud motor vibrations is necessary for this purpose. To characterize mud motor-induced vibrations, a statistical evaluation of averaged vibration measurement data from several runs is conducted. Distributions of the vibrational amplitudes are analyzed, in reference to different designs of the mud motor power section. Analysis continues by reviewing a large quantity of time-based acceleration data with a sampling frequency of 1000 Hz. Special downhole tests are conducted that cover the entire range of operational parameters of the mud motor. High-frequency vibration data with distributed sensors are collected for different motor types and stabilizer configurations. The outcome of the analysis is used to determine the ideal mud motor for a given application. Existing models for drillstring dynamics simulation are fine-tuned. Based on the models, sweet spots for operational parameters that avoid severe vibrations are derived and displayed in an innovative way. The extensive analysis of high-frequency vibration data enables a reliable determination of operational parameters for mud motor applications that correspond to low levels of lateral vibrations. The approach enables efficient drilling with a high rate of penetration and results in increased downhole tool reliability. This ultimately leads to an optimized service delivery for drilling operations.
- Europe > Netherlands (0.28)
- Europe > France (0.28)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Equipment > Directional drilling systems and equipment (1.00)
Abstract Sealing demands have increased due to high and low temperature exposure, intensifying wellbore pressure, and aggressive fluids. Innovative ideas are required to formulate elastomeric compounds and engineer optimized seal geometries in drill through equipment. For static conditions like a BX ring gasket, metal to metal seals generally provide adequate sealing capabilities. However, for dynamic sealing conditions like the actuation of a ram blowout preventer (BOP), elastomers are generally required for well control sealing. The design of annular and ram BOP packers highlight how the use of elastomers with properly designed inserts can close an extrusion gap to improve packer performance. Optimizing the design of the assembly and elastomeric compound is critical to meet challenging performance requirements. Multiple examples demonstrate how laboratory evaluation of elastomeric compounds and full scale component testing improve the final product. Lab tests include procedures such as mechanical properties testing and compatibility testing in drilling mud and other chemicals. Product testing includes full scale fatigue testing, sealing characteristics testing, and temperature testing. The development of annular and ram BOP packers serve as examples of how advances in elastomer technology improve performance and extend service life of drill through equipment.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Drilling Dynamics Data Recorders Now Cost-Effective for Every Operator - Compact Embedded Sensors in Bit and BHA Capture Small Data to Make the Right Decisions Fast
Jones, Steve (Scout Downhole/Sanvean Technologies, LLC) | Sugiura, Junichi (Scout Downhole/Sanvean Technologies, LLC) | Rose, Karl (Varel Intl. Ind., LLC) | Schnuriger, Matthew (Varel Intl. Ind., LLC)
Abstract Historically, everyday drilling dynamics measurements rely on the data captured at Measurement While Drilling (MWD) tools. These measurements only provide data at the location where the MWD is placed in the bottom-hole assembly (BHA). Embedding cost-effective sensors at the drill bit, bit box of steerable motor, top sub of the steerable motor and in the BHA provide data at point of insertion giving a much clearer understanding of downhole dynamics. The sensor package discussed in this paper contains 3-axis vibration, 3-axis shock, two temperature sensors and a new 3-axis gyro. The new 3-axis solid-state gyro sensors were added in the data recorder to measure accurate rotation speed, torsional oscillation and stick-slip at the bit, bit box and other parts of the BHA/drillstring. The data retrieved at the in-bit and bit-box drilling dynamics recorders, along with other points in the BHA, confirmed the effectiveness of "at-point" measurements for correlating bit conditions with downhole drilling dynamics. This granularity of the drilling dynamics data captured "at-point" is typically not seen from an MWD sensor. The in-bit and at-bit measurements revealed critical drilling dynamics dysfunctions that effected bit performance and life. Significant temperature increases at the bit were noted in certain formations where excessive dysfunctions were present. This paper describes the results obtained from "at-point" sensors while drilling in some of the harsher plays in North America Land (NAL). Using proprietary software, the downhole data was merged with EDR data to show the relationship between surface and downhole. Since the bit is typically semi-decoupled from the drillstring (through the mud motor power section), the data gathered from the in-bit and bit-box sensors provide a new dimension of data for bit and drilling tool development.
- Well Drilling > Drillstring Design > Drillstring dynamics (1.00)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Measurement while drilling (1.00)
- Well Drilling > Drilling Equipment (1.00)
- Information Technology > Sensing and Signal Processing (1.00)
- Information Technology > Architecture (0.84)
- Information Technology > Communications > Networks > Sensor Networks (0.70)
An Industry-First 7-5/8 in. Drill Pipe Like Tubular Facilitates Deep Offshore Completions and Interventions by Saving Time and Reducing Cost.
Corbin, Kevin (Chevron) | Begnaud, Taylor (Chevron) | Elliott, Greg (Workstrings International) | Sanclemente, Leianne (Workstrings International) | Babineaux, Joshua (Workstrings International) | Brock, Jim (Workstrings International) | Plessis, Guillaume (NOV) | Muradov, Andrei (NOV)
Abstract Tubulars with gas-tight, rotary-shouldered connections are used as the conduit between the surface vessel (rig) and subsea wellheads in deepwater operations. Requiring no specialized tools and using standard rig equipment, they provide a fast, safe, and cost effective way to run completion landing strings and intervention pipe. Tubulars for these operations must provide a large internal drift diameter to allow for clearance of the wellhead crown plug and installation of completion components. These strings have been limited to 6-5/8 in. pipe allowing for a maximum drift diameter of 5-1/2 in., which is insufficient to run and retrieve the wellhead crown plugs of many large ID subsea trees. Trees with larger crown plugs require operators to use casing tubulars increasing deployment time, requiring casing running crews, incurring higher repair costs and time, thereby increasing overall costs. A completion landing string (CLS) was developed using a 7-5/8 in. pipe and a built-for-purpose, large drift, gas-tight, pressure-rated, rotary-shouldered connection (7-5/8 CLS). This new connection technology optimized the outside diameter and make-up torque to be compatible with the iron roughnecks and pipe handling equipment of the current Gulf of Mexico rigs. Product development and performance validation is detailed with a special emphasis on the enabling connection technology. The paper expands on manufacturing challenges and design choices made to assure ease of rig operations, including modifications to slips and elevators. Finite element analysis (FEA) and physical testing to validate performance are described. Steps taken before the initial deployment to assure compatibility with the rig equipment are explained. Finally, the paper will show data from the offshore field trials and initial deployments. Lessons learned are shared. This industry-first, purpose–built, gas-tight completion and intervention tubular provides 6-1/8 in. internal drift diameter and can be safely deployed using conventional pipe make-up and handling equipment reducing overall cost.
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Equipment (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- (3 more...)
Abstract Wired Drillpipe (WDP) technology provides two-way and high speed measurements from bottom hole and along-string sensors. The data offered by WDP technology has maximum benefit when applied in an automation system or as a real-time advisory tool. Improved control is demonstrated for Managed Pressure Drilling (MPD) with the use of high-speed telemetry and physics-based models. Stabilizing and minimizing pressure within an acceptable bound leads to higher and more consistent Rate of Penetration (ROP). MPD control is challenging due to tight pressure windows and the nonlinearity of the choke and pump response on Bottom Hole Pressure (BHP). This work demonstrates a new Hammerstein-Wiener nonlinear model predictive controller for BHP regulation in drilling. Hammerstein-Wiener models employ input and output static nonlinear blocks before and after linear dynamics blocks and thereby simplify the controller design. The control performance is evaluated in scenarios such as drilling, pipe connections, and kick attenuation. A physics-based drilling simulator, WeMod, is used for model identification and control performance evaluation. The control performance of the new nonlinear controller is compared to conventional controllers in various scenarios. Because of the interconnected multivariable and nonlinear nature of the drilling operation, conventional controllers show severe limitations. In a first scenario, the performance of set point tracking during normal drilling operation is compared. By changing the set point of the BHP, the conventional controller manipulates only the choke valve opening while the nonlinear controller moves choke valve opening, mud pump, and back pressure pump simultaneously. In a second scenario, a pipe connection of a typical drillpipe stand is demonstrated. The conventional controller is not able to regulate the BHP by adjusting the choke valve only. Although a linear version of the controller is able to exploit multivariable relationships, absence of the nonlinear relationships results in severe oscillation when the operational range is shifted outside of the training region. The nonlinear controller maintains a BHP within ±1 bar of the requested set point. A third scenario investigates the kick attenuation performance of conventional and nonlinear control algorithms. The nonlinear controller attenuates the kick within well control conditions, without requiring a well shut-in procedure. Recent advances in drilling simulators and the reliability of the WDP data highway have enabled tighter BHP control. This study presents a robust method to control BHP by applying Hammerstein-Wiener models in an efficient model predictive controller. The proposed methods have been validated in the downstream industry, but are applied for the first time to drilling with nonlinear control functionality. The multivariable control adjusts three main manipulated variables in MPD simultaneously.
- North America (0.46)
- Oceania > Australia (0.28)
- Europe (0.28)
Abstract This paper presents and discusses the results of the field application where a new integrated expandable under reamer technology was implemented in the North Sea. An operator faced issues with wellbore stability and equivalent circulating density (ECD) while drilling a 12¼-in. section in a challanging formation. Placing the reamer close to the bit removed the need for an additional rathole elimination run, avoiding the risks associated with it and saving rig time. The on-command digital, expandable under reamer is fully integrated into the bottom hole assembly (BHA) and can be monitored and controlled from the surface. The under reamer tool has unlimited activation cycles that provide the capability of selective reaming. The flexible placement of multiple reamers in the BHA enables near-bit and main reaming applications, and a combination of both. When used for near-bit reaming service, the reamer can reduce the rat-hole length to 4 m. Significant time savings and safety improvements can be achieved by simultaneously operating the main and the near-bit reamer. In one run, the entire section was simultaneously drilled and underreamed to TD. The first 3,491 ft (1064m) were drilled while simultaneously opening the hole to 13½-in. with the main underreamer. The remaining 233 ft (71m) were drilled and reamed with both the main and the near-bit reamers activated. The rathole length was reduced to 33 ft (10m) in the same drilling run, saving 3 days of rig time. The 10¾-in. liner was then run to the desired depth. Minimal vibrations were recorded in the interval where both reamers were activated and stick/slip was nominal. After the run, an inspection of the reamer blades showed good performance and little wear. The paper will summarize and describe the results and features in detail, and demonstrate how they can help the operators to reduce operational risks and save cost.
- Europe > Norway > North Sea (0.35)
- North America > United States > Texas (0.28)
- Europe > United Kingdom > North Sea (0.25)
- (2 more...)
- Europe > Norway > North Sea > PL 169 > Block 25/8 > Breidablikk Field > Statfjord Formation (0.99)
- Europe > Norway > North Sea > PL 169 > Block 25/8 > Breidablikk Field > Lista Formation (0.99)
- Europe > Norway > North Sea > PL 169 > Block 25/8 > Breidablikk Field > Hod Formation (0.99)
- (5 more...)
- Well Drilling > Drillstring Design > Hole openers & under-reamers (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Equipment (1.00)
- Well Drilling > Wellbore Design > Wellbore integrity (0.89)