bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Holistic Approach to Improving Drilling Performance in Realtime: Integrating Measured, Analysed, Modelled and Reported Drilling Data
Authors: Kucs Richard , Thonhauser Gerhard , Regan Matt , Hanson John , Haugen Jonny , Gundersen Odd Erik 
Published: March 2015

Abstract
The concept of enterprise level and standardised realtime data management solutions supporting drilling operations is rapidly gaining considerable recognition with dynamic and technology-comfortable Operators. Whether delivered physically in an Operations Centre or virtually via web browser, the business drivers are clear – when presented in an ergonomic fashion, the full suite of realtime drilling and geology data enables timely, informed and collaborative decision-making, leading to performance improvement and reduction in operational, and therefore financial, risk.
However, there remains a common disconnect between: (i) primary measured and processed real-time data, (ii) unstructured data in the form of analytical results, and (iii) tertiary metadata from reports. Typically these three tiers of data, and the companies providing them, are isolated from each other. Once operations commence, dataflow may occur in one direction with realtime data feeding into analytics and reporting tools, accompanied by substantial subjective human input. This paper discusses how a major European independent Operator, with a diverse range of global assets and associated challenges, has worked with its various data solution providers to develop and implement a fully bidirectional ‘data highway’ in which realtime, analysed and reported data are seamlessly and efficiently exchanged.
This holistic approach to data-driven operations support delivers a combined value far greater than the sum of the individual applications, as the various proprietary systems enhance and complement each other. Non-productive time (NPT), as well as Invisible Lost Time (ILT) analysis, is fed back into realtime monitoring, reported comments are tied to realtime curves, planned and modeled drilling optimisation recommendations are displayed and correlated alongside live drilling data. Carefully mapped dataflows drive workflows which in turn drive sophisticated deliverables that improve standard operating practices, and hence best practice. The result is improved drilling key performance indicators (KPIs) leading to performance improvement, risk mitigation and cost efficiency: All at an enterprise level and all in realtime.
Pioneer Turbodrilling With 16 ½” Impregnated Bit in Deep Pre-Salt Well in Santos Basin
Authors: Pantoja R. , Britto G. , Buzzá J. , Vieira A. M. , Laroca F. , Appelshaeuser G. 
Published: March 2015

Abstract
Following the major pre-salt reservoirs discovery in Santos Basin by Petrobras in 2006, a large number of exploratory and development wells have been drilled in the area. More recently, some of those wells have been drilled in large wellbore configurations, mostly due to deeper pre-salt layers and geological uncertainties. This paper presents a case study on drilling a deep 16 ½″ vertical section at a deepwater location, where a turbine and an impregnated bit were used because of an extremely tough drilling scenario. This specific run achieved TD at more than 5000m, marking the first record ever of successfully running an impregnated bit of this size offshore.
The basic well design data is shown, as well as the drilling program and offset well and other 16 ½″ bit records. The challenges that were found on drilling deep post-salt 16 ½″ sections in other locations and on the previous BHA runs with PDC bits on this section are highlighted and analyzed with drilling parameters. The impregnated bit specifications and the turbine characteristics are outlined taking operational recommendations into account. Available power at the bit was taken into consideration and the concern with its impact on drilling performance is explained through a comparison with other bit diameters which are widely used.
The bit records, drilling parameters and UCS analysis of the section made clear that the turbine with impregnated bit was the most appropriate and effective drilling system for the scenario at the end of the section. A drilling time and cost comparison with other deep hard-formation-16 ½″ sections drilled in other locations shows that the use of this system may yield significant reduction in the total cost by shortening the overall rig time, making it the preferred option in some future challenging drilling projects.
Lastly, further turbodrilling and impregnated bit improvements are suggested, theoretically analyzed and justified considering drilling performance maximization and drilling tools and rig equipment limitations.
Breakthrough Advance in MPD Automation: A New System Manages Narrower Drilling Window with Reduced Equipment and Crew
Authors: Couturier Y. , Hansen J. , Prent F. , Thow P. 
Published: March 2015

Abstract
The wellbore pressure drilling window for Managed Pressure Drilling (MPD) operations is limited by the proven capabilities of the MPD system to operate within the window for both planned operations and contingency situations. The existing automated annular pressure control system integrates choke control with a real-time hydraulics model and automated auxiliary pump to best manage all states during drilling. However, opportunities to improve performance and reduce equipment footprint and system complexity have presented themselves. With this in mind, based on the strengths of the existing system, an initiative was launched aimed toward a progressive evolution of the system. This paper discusses the development of this improved system with subsequent field trials and the extensive acceptance testing procedures.
At the heart of the evolution was a new choke controller and a change to the valve used to control the choke speed and direction. The new control methodology provides quicker, more precise system control, translating into enhanced pressure control independent of drilling states. Additionally, the control lends itself to quicker calibration, saving substantial rig time.
In the first phase, connection making was developed and tested on a flow loop, followed by a full scale test facility. During phase one field trials, risk was managed by upgrading only one leg of the MPD system before the phase two upgrades were tested. Once phase two developments concluded the system was acceptance tested at a full scale test well against a comprehensive set of test scenarios aimed to validate well integrity amid drilling system failures such as power loss, pump failure and fluid blockages.
This evolution has demonstrated its capabilities in more than two hundred pressure events on actual wells. The system has shown itself to be stable in changing well conditions, requires minimal tuning and retuning, and has reduced the complexity of the system for the control system technician. The system has been validated against downhole tool data to be capable of maintaining bottom hole pressure to within +/- 36 psi (+/- 2.5 bar) in normal operating conditions and within +/- 72 psi (+/- 5 bar) in contingency situations, while minimizing the need for an auxiliary pump.
Frac Plug Drill Out Benefits from Hybrid Roller Cone Bit Design
Authors: Rose Karl , Nobile Kyle , Rodriguez Victor , Rose Randy 
Published: March 2015

Abstract
Improving frac plug drill out in multi-zone completions is an important step in enhancing the development of unconventional assets. The key challenges are efficiency and durability in drilling the diverse materials that make up the 15 to 40 plugs in a typical completion, and addressing the resulting pressure spikes and exposure to high-hydrocarbon fluids that can reduce bit life.
Field observations identified trends in the frac plug bit dull modes, which resulted in a study of operating practices and analysis of what was being drilled. It was found that standard frac plugs have an outer component made of hardened steel, ceramic or other metal, and an inner component of softer composites and rubber. The outer sleeve can damage the bit, while the softer inner component result in large cuttings that are difficult to circulate out of the hole. The process also identified pressure spikes and high hydrocarbon exposure that raised bearing reliability issues.
Reviews with rig personnel, completions engineers, and plug manufacturers were conducted. A series of various bit designs were then run to identify how to best match the cutting structure of the bit with the plug to be drilled.
This review and design process resulted in a patent-pending hybrid roller cone bit with an outer cutting structure of tungsten carbide inserts from a 517 IADC bit, and an inner cutting structure from a 236 IADC steel tooth bit. The tungsten carbide inserts provide a much tougher cutting structure while the steel tooth cutting structure reduces the composite and rubber components to a smaller, more easily circulated cutting size.
This paper examines the review and design process, and presents field results that include the first presentation of a 57-well study conducted in the Eagle Ford shale play in south Texas, where the hybrid bit drilled frac plugs 13.6% faster than standard tooth bits and averaged 3.3 more plugs per use. The authors examine materials and manufacturing contributions, and the role of design software and simulations in optimizing durability and penetration rates. The paper includes operator perspectives on the technology's development and application.
Application of Uncemented Solid Expandable Liner for Combined Openhole Isolation and Casing Repair
Authors: Park M. , Teasdale P. , Cowling M. 
Published: March 2015

Abstract
Well engineers are often presented with a number of potential solutions to drilling challenges as they develop a plan to safely and efficiently execute the drilling program to meet the overall well objectives. The solutions will be evaluated and the option that presents the lowest risk while providing the maximum benefit is normally selected as the preferred solution.
The scope of this paper is to review the challenges faced by a North Sea Operator after identifying the likely presence of high pressure gas stringers in a carbonate formation on a recent brown-field data-gathering well, and the subsequent deployment of solid expandable technology to provide a safe and effective solution. Solid expandable tubulars have demonstrated value as a reliable alternative solution to conventional liners in providing zonal isolation of troublesome formations while maximising drill-through inside diameter (ID). The improved technology and increased reliability in the systems has provided greater confidence that the systems can be deployed successfully with an acceptable level of risk.
The Operator required the isolation of a high pressure gas-bearing zone located below the 9-5/8″ casing shoe to enable the safe drilling and logging of the reservoir section. The use of conventional liners was evaluated but discounted due to the reduction in internal diameter that would prevent subsequent logging and running of the planned liner in the reservoir section. Deepening the 9-5/8″ shoe to cover the high pressure stringers presented higher risks associated with drilling into the anticipated depleted reservoir. After evaluation of the various options, solid expandable technology was selected as the best option to meet the well objectives.
A 7-5/8″ 29.7 lb/ft solid expandable liner system was successfully installed to isolate the high pressure gas stringers located below the 9-5/8″ shoe. The system included an expandable liner hanger set in open hole to provide zonal isolation in place of cement. In addition, the liner lap was extended back into the 9-5/8″ casing to isolate a leaking stage tool. The application of both repairing a casing leak and isolating a high pressure open hole zone using an uncemented liner was a first for the Operator. This allowed the Operator to drill the reservoir section with a lower mud weight while minimizing the risk of differential sticking and losses, the logging program to be conducted as desired and the 5-1/2″ fibreglass liner to be installed as planned. The safe and successful drilling of the well, coupled with the capture of desired information met the Operator's well objectives, adding value to future field development.
While this was the first solid expandable installation in this size for the Operator in the area, their confidence in the technology from previous installations allowed them to adapt the system to provide the required open hole zonal isolation whilst also reinstating integrity to the 9-5/8″ casing.
High Speed, Continuous Single Well Magnetic Ranging
Authors: Hanak F. Chad , Estes Robert 
Published: March 2015

Abstract
Passive magnetic ranging (PMR) is a technique used to determine the range and direction to a cased well that may not be accessible during the drilling of an adjacent well. It has been used since the 1970s (wireline) in relief wells and anti-collision applications where dual-well active ranging techniques cannot be used [Grace, Robinson and Vogiatzis, 1972, Morris et al., 1978]. PMR in MWD tools is a nascent business, and encountered some early resistance [Towle and Van Steenwyk, 1999]. It requires very accurate magnetometer measurements, preferably corrected in-situ for residual bias errors, a large number of static surveys, and manual interpretation of the data. All of this has made PMR a slow process, and thus it has not been widely adopted in markets such as the steam-assisted gravity drainage (SAGD) market in Canada, where speed is essential.
A new PMR technique is outlined in the paper that achieves speed and accuracy comparable to dual-well active ranging techniques. It uses existing MWD magnetometer hardware, but does not require an excessive number of surveys or pre-magnetization of the casing in the offset well. Using Kalman filtering techniques adapted from aerospace navigation algorithms, the single-well technique provides continuous ranging output while enabling nearly uninterrupted drilling [Gelb, 1974].
The paper includes a discussion of the theoretical underpinnings of the technique and detailed field test results. The ranging algorithm was shown to be robust in above-ground testing, consistently converging in the presence of gross initial position uncertainty. A vertical test well drilled using the new ranging system demonstrated successful ranging over a wide span of well-to-well distances. The MWD ranging estimate showed good agreement with a pair of gyro surveys (test well and cased-target well) performed after tests conclusion.
MWD tools with PMR can be broadly applied to enhance accuracy, speed, and safety in markets for SAGD, anti-collision and relief well drilling.
Conical Diamond Element Bit Sets New Performance Benchmarks Drilling Extremely Hard Carbonate/Chert Formations, Perm Region Russia
Authors: German Vyacheslav , Pak Mikhail , Azar Michael , Bits Smith 
Published: March 2015

Abstract
Developing reserves in the northern portion of Russia's Perm region frequently requires the operator to drill extremely hard carbonates which contain high concentrations of problematic chert inclusions. Drilling the chert with PDC bits has been challenging and in many cases impossible due to the cutters' inability to withstand high impact forces which resulted in severe cutter damage. Both rotary and motor BHAs have been utilized in an attempt to mitigate shock and vibration.
Rollercone TCI bits are a viable option but slow ROP and short runs combined with high total bit revolutions caused numerous trips for tool change out. It was evident that PDC's shearing action was the most efficient rock failure mechanism and had the greatest potential to drill extended meters at higher ROP compared to a roller cone's crushing action. The operator required a new type PDC bit that could efficiently drill long intervals of carbonate/chert formation at high ROP and a cutting structure that would remain intact when encountering the chert intervals.
To develop a durable bit solution, engineers used an FEA-based modeling system to implement an innovative hybrid-type bit by strategically positioning multiple conical diamond elements (CDE) and conventional PDC cutters across the entire cutting structure from bit center to gauge. This new-style cutting structure leverages the CDE's aggressive shape and superior impact and wear resistance to create a high-efficiency plowing/shearing action that improves performance in difficult formations. The analysis indicated the new hybrid bit would improve performance and be capable of surviving shock and vibration while drilling the hard carbonate/chert formations.
The hybrid CDE bit was tested and compared against two direct offsets in Russia's North Perm Unvinskoe field. Unvinskoe field was selected for the case study because the formations and application challenges are similar to several other northern Perm fields. The first well was drilled entirely with roller cones which required 10 runs delivering average meterage of 149/bit at an average ROP of 6.05 m/hr. The second well required three roller cones and three 913-standard type PDC bits delivering average meterage of 213.4/bit at an average ROP of 9.65 m/hr. The third well was drilled with one roller cone, one standard PDC with averages of 336m at 8.2 m/hr and two hybrid CDE bits with averages of 433m at 15.6 m/hr. Performance improvement for the CDE bit runs versus offsets runs in wells were: 1) Well-1 190% more meters, 157% faster ROP; 2) Well-2 103% more meters, 62% faster ROP; 3) Well-3 29% more meters, 90% faster ROP.
Reducing Well Delivery CostsThrough Practical Experience Gained Implementing an Integrated Drillship Design and Automation of Drilling Equipment
Authors: Adams Ed , Wijning Dieter 
Published: March 2015

Abstract
Ultra-deepwater well construction presents very unique technical and economic challenges to deepwater operators worldwide. Wells are now being planned and drilled in water depths up to 12,000 ft and total depths beyond 30,000 ft. The technical complexity of these wells requires enabling rig technologies to get the wells drilled safely and competently. Moreover, their extended well delivery times and associated economic impact forces operators to explore new ways to control unit development costs and Returns on Capital Employed (See Slide 2). Key to achieving such cost control is improving rig efficiency and focusing on flat time reduction.

Practical experience gained through continuous development (see Slide 3) created an integrated drillship design and a new approach on how to automate, not mechanize, the drilling equipment on mobile offshore drilling units. Combined, these principles can significantly reduce flat times and, thereby, reduce well delivery costs.
A Barrier Analysis Approach to Well Control Techniques
Authors: Fraser D. , Moore D. , Staak M. Vander 
Published: March 2015

Abstract
Drilling fluid is one of the most dynamic and critical barriers used during the drilling process. The fluid barrier must be properly monitored and maintained at all times to be reliable as a barrier. The objective of this paper is to apply the risk-based technique of barrier analysis while utilizing key performance indicators (KPIs) in order to aid in the comparison and evaluation of well control techniques. In a barrier analysis, the fluid pressure barrier is sustained as long as the fluid pressure lies between the pore pressure and the fracture gradient of the formation. This is the critical function of the barrier. A success path is a systematic listing of the steps required to maintain the critical function of the barrier. When the development of these safety functions and success paths are combined with variances and the kick performance indicators (the Kick Detection Volume [KDV] and the Kick Response Time [KRT]) proposed in a recent paper*, the power of the approach begins to emerge. For well control, this analysis demonstrates that a combination of techniques commonly used in managed pressure drilling (MPD) can significantly reduce risk. While there are a variety of MPD techniques available, this paper focuses on the constant bottomhole pressure [CBHP] method from a floating rig as an example that illustrates a number of techniques that can be used for both subsea and surface BOP stacks, offshore as well as on land. Closing in the fluid system provides high resolution fluid pressure measurement and control along with the ability to directly measure a.) In-situ fracture gradients, and b.) Pore pressures at key places in the wellbore, without completely halting the drilling operation. By manipulating Surface Back Pressure (SBP) to hold downhole pressures relatively constant, the swab and surge effects in the wellbore can be minimized, providing even greater assurance that the critical function will be maintained. This directly eliminates or reduces the reason kicks occur during connections and while tripping out of the hole. Since these are the most common times when kicks occur*, we suggest that the overall number of kicks taken while drilling could be cut by as much as half. Measured vs. calculated input flow is also demonstrated to be beneficial for reducing risk since it reduces the likelihood of drilling fluid density error and provides for a more complete understanding of what is in the well bore at any given time. Plus it reduces the KRT by increasing confidence in detecting flow differentials to the point that action may be taken immediately. Finally, we make the observation that the barrier analysis technique used is not specific to drilling, but is an approach that can be applied in other areas to compare technologies and risk and to identify processes that can be used to mitigate process safety issues.
CFS v. MPD- Revolutionary Technology to Outshine Industry Leader?
Authors: Cunningham Justin R. , Ozegovic Alek , Grayson Brian M. , Salvo-Shook Constance 
Published: March 2015

Abstract
As the industry-wide adoption of managed pressure drilling (MPD) continues, the recent emergence of reliable continuous flow systems (CFS) are right on its heels, offering many parallels in wellbore pressure control and protection. The question then presents itself—does continuous flow outperform conventional MPD? Will the industry's adoption of CFS lead to the ultimate obsolescence of the current offerings, or will both coexist? This paper will examine the pros and cons of each system and their respective abilities to mitigate hazards and optimize drilling efficiency.
Conventional MPD systems utilize a rotating control device (RCD) and a choke manifold system to create a closed loop circulation system and achieve precise control of a wellbore's pressure profile during drilling and completion. CFS also works to achieve greater control of wellbore pressure through continuous circulation of drilling fluids. A large percentage of all drilling hazards related to wellbore pressure occur when mud pumps are cycled off and on during connections, which causes fluctuations in equivalent circulation densities (ECD) and downhole pressure spikes.
This paper examines and compares two state-of-the-art technologies for enhanced pressure control and drilling efficiency; CFS and choke-based MPD systems. The conclusions will highlight the directions of the two techniques and determine if they will coexist or will forever compete in the industry to be the most widely-adopted choice.