bluuebunny/crossref_metadata_2025_split huggingface dataset:
Safer Tripping Through Drilling Automation
Authors: Chmela Bill , Gibson Nicholas , Abrahamsen Egill , Bergerud Ronny 
Published: June 2014

Abstract
Automation consists of the use of control systems to control processes, reducing the need for human intervention. There has been considerable progress made in automating key tasks on the drill floor (i.e. mechanization), and in providing control of the weight on bit and bit rotation, etc. (e.g. Dupriest, 2005) to optimize the rate of penetration. In this paper we look at a stepwise implementation of adaptive drilling automation that responds to changing conditions in the wellbore.
Within well construction, one specific process that may be well suited to this adaptive automation is the tripping of drillpipe or casing into or out of the well. Tripping operations today are guided by pre-drill analysis to determine safe tripping speeds and require the driller to react to changing downhole conditions to avoid problems such as swab, surge, or hole collapse. In this paper we describe a stepwise approach to partial adaptive automation of the tripping operation. The stepwise approach consists of continuously performing engineering-while drilling calculations to determine the dynamic hydraulic pressure profile variations within the wellbore at all depths for any driller-induced string motions or pump rates. Next we use these calculations to determine safe operational envelopes for the drilling machinery (accelerations, decelerations, rates and velocities), helping the driller to trip pipe in or out of the well while ensuring that the full wellbore hydraulic pressure profile always stays within the prescribed safe geopressure window based on current conditions. Finally, we reach the automation step where the operational envelopes guide the automated control of the drilling equipment.
Development and Testing of Stick/Slip-Resistant PDC Bits
Authors: Schwefe Thorsten , Ledgerwood L. W. , Jain Jayesh R. , Fuselier Danielle M. , Oueslati Hatem , Endres Lance 
Published: June 2014

Abstract
Stick/slip vibrations are known to cause damage to drill bits and other drilling system components. Recent investigations reported by the authors determined that the design of polycrystalline diamond compact (PDC) bits has a significant influence on stick/slip behaviour of the drilling systems. Among various bit design methodologies, a depth-of-cut (DOC) control technique has emerged as an effective way of mitigating bit-induced stick/slip. The research reported in this paper aims at enhancing this technique to accurately identify the optimal application of DOC control for maximum reliability and performance.
A comprehensive testing program on a full-scale research rig was undertaken to characterize the optimal type, positioning, and extent of DOC control required for mitigating stick/slip. Several PDC bits incorporating strategically configured DOC control elements were designed and tested. The stick/slip tendencies of bits were determined based on diagnostics from downhole drilling dynamics monitoring devices while the surface operating parameters were varied in a controlled manner.
Test results indicated that certain DOC control characteristics were the most effective in mitigating stick/slip. While under-application of DOC control did not mitigate stick/slip, over-application reduced performance without mitigating stick/slip. Formation type played a major role in instigating stick/slip, and was a significant factor in designing DOC control.
The paper presents analysis details and proposes design guidelines based on testing in multiple formations within three research wells. These design guidelines are also supported by field evidence from the North Sea, where statistics on many bit runs indicate superior performance with properly tuned DOC control.
Relief Well Planning
Authors: Flores Vanessa , Dailey Penny , Todd David , Mathur Rohit , Donadieu Brian 
Published: June 2014

Abstract
Relief well planning can be a critical safety measure, ensuring readiness and rapid response in the event of a catastrophic blowout that threatens human life and the environment. Recent regulatory changes in the oil industry have spurred a demand for extensive relief well planning for shelf and deepwater wells around the world. This paper discusses well planning, trajectory design, and drilling as it applies specifically to relief wells.
A relief well is drilled adjacent to an existing well that has suffered an uncontrolled release of pressurized hydrocarbons. From an operational standpoint, a relief well is drilled only if surface intervention or capping attempts are taking too long or have failed to stop the flow. The goal of the relief well is to divert the pressurized hydrocarbons up a new wellbore in a controlled manner or to kill the blowout well with heavy mud and secure it with cement. For either remedy to succeed, precise interception of the existing wellbore becomes a key component in relief well design. This, in turn, makes the entire relief well planning component a very crucial and challenging aspect of the well design.
This paper focuses on five phases of relief well planning:
Surface location selection, including shallow hazard assessment, metocean considerations and rig logistics. Selection of drilling, evaluation, ranging and interception tools. Directional trajectory design utilizing a bottom-up approach. Project execution (drilling operations). Intercepting the well considering cased hole, openhole or the reservoir section of the blowout well.
The United States Bureau of Safety and Environmental Enforcement (BSEE) requires all operators to provide documentation demonstrating their capacity to drill a relief well. Operators in the Gulf of Mexico must submit the surface location for a relief well along with their application for a permit to drill. Two locations are generally identified, and relief well paths are planned for each at every casing point prior to an interval where hydrocarbons may be encountered. As many factors can change while drilling, the planned relief well paths would require appropriate modification, but the initial plans prove feasibility and provide a basis upon which a plan to an actual wellbore could be quickly designed. The regulations ensure safe planning and execution in response to a hazardous situation, and they are in the process of being adopted by worldwide government agencies.
A New Continuous Flow System (CFS) for Managed Pressure Drilling
Authors: Cunningham Justin , Bansal R. K. , George Geoff , De Leon Eisenhower 
Published: June 2014

Abstract
Continuous circulation of drilling fluid offers many benefits, including increased control of downhole pressure in relation to pore and fracture pressures along with enhanced wellbore cleaning. Although the concept of continuous circulation has been known to the industry for a long time, it has gained significance in recent years with real-time downhole pressure monitoring and control. Continuous circulation provides an uninterrupted data stream from downhole sensors and surface equipment even while making a connection, thereby never losing downhole pressure.
Weatherford has developed a continuous flow system (CFS), including subs that crown the top of a drillpipe stand and an automated control system that switches mud flow between the top drive and the side flow port. During conventional drilling operations, CFS subs are passive drillstring components. When a new stand needs to be added, a CFS sub connected to a stand already drilled into the well is positioned in the rotary table, and a clamp carrying a side flowline is attached to it. Once the clamp has been securely attached, rig hands can move off the rig floor and conduct the rest of the operation from a remote control panel. At this point, the CFS sub works like a three-way valve. When a sleeve inside the CFS sub is pushed upward, it opens a side flow port on the sub and simultaneously closes an internal valve to cut off flow from the top drive. With concurrent operation of mud valves on a manifold skid, mud flow is redirected from the top drive to the side flow port before breaking the top-drive connection. Mud flow is also directed back to the top drive after adding a stand. The CFS can be used during trip-in and trip-out operations in an almost identical manner.
Significant advantages of the CFS are easy implementation into the rig flow loop, automated switching of flow from the standpipe to the side entry port and back from a remote location, high consideration for personnel safety, limited impact on connection time, and a small footprint on the rig floor.
Instrumented Motors Prove Crucial in Unconventional Well Placement
Authors: Wright Anthony , Snyder John 
Published: June 2014

Abstract
Near-bit, instrumented motors are a transformative technology used for unconventional well placement. Near-bit sensors are located closer to the bit compared to traditional measurement while drilling (MWD) sensors, which are normally &gt;20 ft behind the bit, thus allowing the opportunity for exiting thin bed formations before a formation change can be observed on the logs. These tools are also instrumental when choosing the formation tops for each new boundary drilled. The gamma-at-bit-inclination sensor system provides at-bit azimuthal gamma ray and inclination measurements for improved geosteering and optimum well placement. This paper describes the geosteering capabilities of a newly released 6 3/4-in. sensor in different formations.
In a single run, the gamma-at-bit-inclination sensor system successfully delivered a hole section of 4,952 ft (2,248 to 7,200 ft) in 43.5 drilling hr, with an average rate of penetration (ROP) of 114 ft/hr in depleted shale and sandstone formations on the Gulf of Mexico (GOM) continental shelf, eliminating additional bottomhole assembly (BHA) changes; a 4,043-ft (7,442 to 11,485 ft) lateral in 23.5 drilling hr with an ROP of 172 ft/hr in Oklahoma City (OKC), Oklahoma; and 4,781 ft (479 to 5,260 ft) in 37.75 drilling hr at an ROP of 127 ft/hr in the Woodford shale of the Mississippi Lime, with zero non-productive time (NPT) or health, safety, and environment (HSE) incidents.
The use of near-bit, instrumented motors allows remaining in the zone of unconventional plays longer. To date, a total of more than one million feet has been drilled using a smaller near-bit, 4 3/4-in. instrumented motor, and running with larger-sized tools has proven successful. Instrumented motors previously had limited drilling application; however, with the geosteering requirements for unconventional well placement, a greater range of applications for the measurements provided by the near-bit, instrumented motors has been identified.
Application of Real-Time Process Control and Engineering Software Simulation in Foam Cementing
Authors: Dooply Mohammed , Elhancha Anouar , DeBruijn Gunnar , Gubanov Evgeny , Voloshchuk Maxim 
Published: June 2014

Abstract
Foamed cement operations not only require a solid knowledge of the foam quality during placement, but also good control of nitrogen injection throughout the operation. These two factors ensure optimum well control during placement and provide well integrity after placement completion.
A real-time foamed cement process control system is capable of handling dramatic changes in the cement slurry pump rate which allows for delivering quality foamed cement with the designed proportions of gaseous nitrogen and surfactants. The process-controlled system can also perform operations with more than 200 stages of varying nitrogen ratios to provide a near-constant density column of foamed cement in the wellbore.
A dynamic compressible fluid placement simulator provides better understanding on the evolution of foam quality across the wellbore during the placement. The simulator computations take into account the influence of circulating pressures and temperatures on nitrogen compressibility. The simulator then evaluates the computed surface and downhole pressures and foam qualities throughout cement placement and after cement in place, and issues warnings whenever those parameters fall outside the design criteria at any time during the operation. Such feedback allows the engineer to adjust the design to meet the job objectives.
The combination of these two technologies effectively reduces the operational complexities on foamed cement operations, which will substantially increase the success rate and enhance well integrity. Several case studies of foamed cement operations performed in the Gulf of Mexico are presented in which the use of real-time process control and dynamic placement simulation provided successful job execution and proper cement placement.
Automated Planning of Procedures for Risk Mitigation and Efficiency
Authors: Molin Arthur , Kortenkamp David , Bonasso R. Peter , Schreckenghost Debra , Bell Scott , Kusy Kevin 
Published: June 2014

Abstract
To effectively manage drilling operations is an enormous challenge. The work must be carefully planned and scheduled, but unforeseen events may force changes in the plan at any time. An efficient plan of operation is vital to ensure that work is performed safely and efficiently, that risks are managed appropriately, and that the cost of the operation is controlled. Maintenance tasks must be performed on schedule; if necessary maintenance tasks are delayed the costs associated can balloon or health and environmental risks might arise. However, routine maintenance must be scheduled to minimize the impact on ongoing operations.
The National Aeronautics and Space Administration (NASA) is currently pioneering work on using automated planning and scheduling to manage the work performed during Extra-Vehicular Activities (EVAs) on the outside of the International Space Station (ISS). These EVAs are the most difficult activities performed by the astronauts on the ISS, and each one is planned to maximize efficiency and minimize risk. The time available for an EVA is strictly limited both by the life-support system and human endurance, and every minute must be utilized properly.
NASA is developing a technology for representing procedures, or the tasks that must be performed during the EVA. The procedures encode the time estimated for the task, the tools and equipment needed, any preconditions for the task to be performed, and also the state of the system at the end of the task. An automated planner has been developed that can take a high-level goal plus those procedures, and:
produce a plan of operation that attains the goal while ensuring the tools and equipment are available when needed, ensure limited resources such as oxygen are managed efficiently, ensure the safety equipment is not overloaded, and ensure that no performance rules are violated.
The system can track the usage of tools and equipment and automatically update inventory databases at the end of the EVA to represent changes in location, to simplify the beginning of the next EVA. In the event of unforeseen events, the automated planner can re-plan the remainder of the shift.
This planning technology developed for NASA has potential to improve the safety and efficiency of drilling operations. Risks associated with safety-critical activities can be reduced by validating the sequencing of these activities to ensure there are no missing steps or misconfigured systems that could lead to accidents. Compliance with safety policies can be improved by modeling these policies as constraints on how drilling activities should be performed. Logistics for drilling preparation and operations can be improved by automatically deriving the tools and equipment needed based on the tasks to be performed. This paper will describe the planning approach implemented for NASA, and will identify how that approach can be used to improve drilling operations.
Identifying and Surviving a 1500 ft Long Keyseat @18,000ft – A Case History and Lessons Learned
Authors: May Richard , Perez Carlos , Perdomo Andres , Jiménez Africa , Angel John , Salinas Nelson , Rodriguez Efrain , Angarita Camilo , Mierez Jose 
Published: June 2014

Abstract
The Bricol field is a naturally fractured reservoir, located in Southern Mexico primarily producing from a deep objective in the Upper Jurassic Kimmeridgian formation. The geological complexity includes fracturing, salt bodies, high pressure and temperature.
While drilling an HPHT directional well at 18,820 ft below an 11 ¾" drilling liner set at 13,763 ft, that required directional drilling with a 10 5/8" pilot bit, rotary steerable system (RSS), and simultaneously under reaming to 12 ¼", serious drilling operational problems were encountered. Severe hole drag in excess of 150,000 lb as well as high shock and vibrations were encountered that ultimately resulted in a drill string twist off, jeopardizing the success of the well.
After successfully fishing and recovering the twisted off drill string, a multidisciplinary team collaborated to find the root cause of the drilling problems. Wireline logs were run, including a six arm oriented caliper log, which identified a Keyseat in the wellbore, located between 16,733 ft – 18,275 ft (Length 1542 ft). A detailed review and evaluation of the wellbore conditions at that depth interval was performed in order to identify the root cause of this anomaly. The 12 ¼" hole section was successfully finished and the 9 7/8" liner was run and cemented
This paper will give a detailed description of the problems encountered and the unique solution that was developed to overcome problems on future wells, during the planning stage through sensitivity analysis to improve the trajectory. In cases where the trajectory cannot be modified we have recommended preventative actions to minimize drilling problems.
New Applications of Cementing Valve Technology for Gulf of Mexico Deepwater Operations
Authors: McNicol Jim 
Published: June 2014

Abstract
Deepwater wells face a myriad of challenges, amongst which are: narrow pore pressure-fracture gradient margins, salt sections and salt exits, cementing operations in relatively weak formations, management of annular pressure buildup (APB) in un-cemented annuli and well integrity assurance for life of well. New methodologies and a novel new stage cementing system has been developed to address these challenges.
In a recent Gulf of Mexico well, a 16" liner primary cement job secured the bottom of the section but did not cover sufficient height of the salt section to provide adequate zonal isolation and created an APB issue. A planned second stage cementing operation was performed using a new cementing valve that was tested to the same gas-tight regime as the V0 specification employed in ISO14310. Two cementing valves were run on the 16" liner string; one at the top, immediately below the liner hanger and one near the bottom. A drillpipe deployed cementing tool was RIH to shift the upper cementing valve open and pump a large quantity of cement down the annulus from the liner hanger to the top of cement left by the primary cement job; the upper valve was then closed and tested. Further operations, including logging verified the cement job integrity.
The paper will discuss the operation in detail and explain how performing a second stage cementing job "top-down" through a cementing valve, as opposed to conventional cementing circulation, resulted in full zonal isolation throughout the entire section; and eliminated many of the issues described before. The paper will present additional benefits such as fully filling the liner annuli to eliminate APB and improve well integrity for life of well. There will be an evaluation of future opportunities to improve zonal isolation in salt sections; create secure wells in areas of depleted sands; and access narrow margin areas of interest with low pore pressure-fracture gradient.
Combining MWD Ranging Technology and Gyro While Drilling (GWD) In High Inclination Wellbores Deliver Reduced Drilling Costs and Complexity without Compromising Safety
Authors: Duck C. H. , Beattie K. , Lowdon R. , McElhinney G. 
Published: June 2014

Abstract
The uncertainties associated with current wellbore surveying techniques can generate time consuming challenges when sidetracking around a fish at high inclinations. If the sidetrack is not planned with a significant safety margin and/or the bottom hole assembly does not include the proper amount of non-magnetic spacing then the MWD surveys of the sidetrack wellbore can be compromised significantly by external magnetic interference leaving the well to be drilled blind. One means of monitoring the approach between a drilling well and a secondary wellbore has been to use the MWD sensors to monitor for external magnetic interference. When monitoring the convergence of two wellbores in a close approach situation, the relative positions between the wells must be calculated. However, calculating the relative position between wells is a challenge when the inclination of the two wellbores exceeds 80 degrees.
This method increases safety while drilling. Using gyro while drilling eliminates the need to run wire line conveyed gyros, saving considerable expense. Gyro while drilling (GWD) allows data to be collected frequently while the drilling progresses, minimizing the risk of intercepting the fish without slowing the drilling process. Equally it is possible to be flexible in sidetrack trajectories as any attitude is available. There is no longer a need to steer by inclination only, improving efficiency in drilling operations.
This paper looks at a case study where a passive MWD ranging method uses both the output of the magnetic sensors from the MWD and the directional information calculated from an all attitude gyro while drilling tool. This allows the calculation of the spatial relationship (distance and direction), between the drilling well and the fish, at 90 degrees of inclination. As the drilling sidetrack and the fish are at 90 degrees inclination and the two wellbores are not parallel, a high inclination gyro must be used to calculate the azimuth required for passive ranging calculations. Since an electromagnetic target cannot be placed in the original hole, only a single entry ranging technique can be used. This tool combination allows the positional relationship between the drilling well and the fish to be continuously monitored until the collision risk has passed.