bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case History: Deepwater Drilling Campaign on the Norwegian Continental Shelf in 2008 and 2009: A Success Story
Authors: Cruickshank Stian Haugland , Kirkemo Erik Gustav , Gabrielsen Glenn , Hovden Øystein , Tryland Reino Tommy 
Published: February 2010

Abstract
Statoil drilled 7 deepwater wells, including one sidetrack, on the Norwegian Continental Shelf from 2007 to 2009. The semi-submersible rig Transocean Leader was used for these drilling operations.
All the wells were drilled and abandoned in a total of 460 days, some 135 days ahead of schedule. Gas and/or condensate were discovered in 6 out of these 7 wells. The wells were all drilled with higher efficiency compared to previous deepwater wells drilled on the Norwegian Continental Shelf. The water depth for the wells ranged from 950 m to 1350 m.
In the planning phase, the proposed well designs were challenging. However, continuous improvement in drilling performance and risk management were achieved through comprehensive and systematic work in the multi-disciplinary project team of geologists and drilling engineers. Additional contributing key factors to success were good cooperation and planning between the offshore and onshore project team including personnel from the rig contractor and service companies.
In the planning phase, early identification of technical challenges and solutions were discussed. Key learning from international deepwater projects in StatoilHydro and other operators were also highlighted.
The geological and pore pressure prognosis for all the wells were quite accurate compared to the measured values during drilling and logging.
This paper describes how deepwater exploration wells were planned and successfully completed with Transocean Leader. Good teamwork between offshore and onshore contributed to this success story.
Selecting Drilling Technologies and Methods for Tight Gas Sand Reservoirs
Authors: Pilisi N. , Wei Y. , Holditch S. A. 
Published: February 2010

Abstract
As compared to a well in a conventional gas reservoir, a well in a tight gas sand (TGS) reservoir will have a lower productivity index and a small drainage area. The economic risk involved in developing a TGS reservoir is much higher than the development of a conventional gas reservoir as the economics of developing most tight gas reservoirs borders on the margin of profitability. Therefore, it is important to select the appropriate drilling method and technology to drill a given TGS reservoir condition. In our review of the petroleum literature, we have found few papers that provide a logical method for selecting the best drilling method and technology for a given set of reservoir conditions. There are individual papers that discuss individual, successful field cases where specific drilling methods and technology seem to work for specific reservoirs. We have used many of these SPE papers to help define "best-practices" concerning the selection of drilling technologies and methods. We then developed logic to provide advice on the best drilling technologies and methods for specific reservoir conditions. In this paper, we will explain the logic we have developed for choosing drilling technologies and methods for drilling a TGS reservoir.
For several years, we have been working on software we call TGS Advisor. TGS Advisor can be used to provide advice to engineers developing TGS reservoirs. The program can be described as an ‘Advisory System’. The user enters the known reservoir data and the program provides advice on how to drill, complete and stimulate the reservoir. We have combined knowledge from the petroleum literature and interviews with experts to build the TGS Advisory system. We evaluated the results of the advisory system with published case histories in the SPE literature. In this paper, we will describe how we have included the selection of appropriate drilling technologies and methods used to develop TGS Reservoirs.
Unusual Underwater Pile Driving in "Iceberg Alley" off Newfoundland, Canada
Authors: Harris David , Adams Paul G. , Bell Doug 
Published: February 2010

Abstract
This paper will describe the planning and execution of an unusual project for driving pin/foundation piles underwater with hydraulic hammers, in water depths up to 155 meters [ 510 feet ] offshore Eastern Canada.
The North Amethyst project is a series of tie-back satellites to the " Sea Rose " FPSO located in the White Rose area, approximately 300 miles [ 483 kilometers ] offshore from St.John’s, Newfoundland, Canada. This is in the so called " Iceberg Alley ".
The operator was Husky Oil and the prime contractor for the installation was Technip Canada Ltd. The subsea equipment is located in excavated " glory holes " where the top of the seabed equipment is placed approximately 3 meters [ 10 feet ] below the surrounding sea bed level to protect against iceberg scour.
The operations involved the installing of pin and foundation piles for both Manifold Support Frames [ MSF] and Subsea Distribution Units [ SDU ] from Technip’s support vessel, the " Well Servicer ", mobilized from Bay Bulls dock, near St.John’s, Newfoundland.
Four piles were required for each of the Manifold Support Frames and four piles were required for each of the Subsea Distribution Units. A total of fifteen 24 inch piles were driven [ 24 inches OD X 1.5 inch wall X 52 feet long, 610 mm X 38.1 mm wall X 15.8m long ].
Also six 36 inch X 1.5 inch wall [ 915 mm OD X 38.1 mm wall ] piles were driven.
Each pile was driven approximately 13 meters [ 43 feet ] below the mud-line in water depths ranging to 155 meters [ 510 feet ].
This paper will show how by careful design, pre planning, fabrication and the carrying out of a comprehensive Factory Installation Test [ FIT ] in Louisiana prior to the job, a successful operation was achieved in a very challenging operating area.
Novel Selection Tool Enables Scientific Approach to Matched Assemblies
Authors: Barton Steven , Murdock Andy , Gee Ryan 
Published: February 2010

Abstract
Matching the drill bit to a directional motor assembly is critical to efficiently attaining the desired well trajectory. However, selecting the correct bit for the motor in a vertical application is just as vital. If the bit is too aggressive, it can stall the motor and significantly reduce the average rate of penetration (ROP). It will also increase the likelihood of premature failure of the elastomeric liner of the motor power section or twist off of internal motor components. If the bit is not aggressive enough, it will not make full use of the available motor power and the ROP will be sub-optimal.
To ensure consistent and accurate matching of the bit to a specific downhole motor, an interactive, intranet tool was developed. This software incorporates logic regarding the configuration of the motor power section and assesses this against key characteristics of the drill bit including length, profile, gauge geometry, cutting structure, and secondary torque control components. The tool enables the user to first select the motor type and the key parameters from which the expected motor RPM, torque, and power are calculated.
This information can then be utilized to identify the ideal bit design based on the four fundamental performance indices, derived from a sophisticated mathematical model. These indices describe the performance of the bit in terms of ROP, Stability, Durability and Steerability. They represent a scientific and accurate means to match the relative aggressivity of the bit to the torque output of the motor.
Several case studies are documented which clearly demonstrate that matching the drill bits to motor power sections delivers greatly improved drilling efficiency and significantly lowered drilling cost. As a result, the latest generation of even-wall technology mud motors has been utilized to their full potential.
High Frequency Downhole Dynamic Measurements Provide Greater Understanding of Drilling Vibration in Performance Motor Assemblies
Authors: Craig Andrew D. , Goodship Rachel , Shearer David R. 
Published: February 2010

Abstract
The use of downhole mud motors to improve drilling performance in vertical wells is becoming more common throughout the oil and gas industry. The additional torque provided by a downhole mud motor allows for a more aggressive drill bit design to be selected, and achieve a greater ROP. This paper will present a series of case studies where a near bit dynamics recorder has been used to determine the dynamic conditions below a motor. In several cases a dynamics recorder was also located above the motor, providing two discrete points of measurement.
In the first case, near bit dynamic measurements allowed for BHA stick-slip to be identified as the cause for severe bit damage rather than difficult formation as was suspected. In the second case study, a near bit recorder coupled with a recorder above the mud motor identified that a significant level of vibration was generated by the motor. A different motor design was used on the following well and a reduction in vibration severity allowed for the section to be drilled in a shorter time. In the third case study, frequency analysis of near bit dynamic data conclusively identified backwards bit whirl as the cause for severe bit damage.
In conclusion, the use of a near bit dynamics recorder has allowed for a greater understanding of the dynamics involved in performance motor assemblies. The application of this knowledge has helped to address the root cause of previously misunderstood vibration problems and improve drilling performance.
Spud to Reservoir—With Casing While Drilling (CWD)/Polycrystalline Diamond Compact (PDC) Drill-out Technology Using an Automated Drilling Rig
Authors: Gussinklo R. T. , Hepp B. A. , Swart D. , Wingate J. H. 
Published: February 2010

Abstract
The first well drilled on any newly commissioned rig is fraught with challenges. This paper describes how these challenges were met with the successful introduction of Casing while Drilling (CwD) and polycrystalline diamond compact (PDC) drill-out bits, employed over the entire length of a vertical exploration well.
The operator planned to drill a 12 1/4-in. hole from surface using a CwD bit conveyed on 9 5/8-in. casing. The intermediate casing (7-in.) would also include a CwD bit to ensure casing was set at the correct depth. The intermediate hole (8–1/2-in.) and reservoir section (6-in.) would entail drilling-out the previously run CwD bits and then continuing to drill to section Total Depth (TD).
CwD and PDC drill-out technologies were used to successfully drill from surface down into the reservoir (2,418m total length). CwD was used to drill and simultaneously case the 12–1/4-in. hole section with 9 5/8-in. casing to a depth of 780m. The 8 1/2-in. bit drilled-out the 12 1/4-in. CwD bit and drilled on to section TD at 2,075m. The 7-in. casing with an 8 1/2-in. CwD bit was successfully set at depth even though the casing stood up at 1,924 m and had to be drilled to bottom using the CwD bit. A 6-in. PDC bit successfully drilled out the 8 1/2-in. CwD bit and continued on to drill to 2,418 m. The well was completed and suspended inside the budget Authorisation for Expenditure (AFE).
This was the first well drilled with a newly commissioned state-of-the-art semi-automated drilling rig using CwD and PDC drill-out technology. The well included the first CwD run in the Netherlands. The 12 1/4-in. CwD run was the longest run in the Eastern Hemisphere with this system, drilling from surface to 780 m. The first 2,418 m (90%) of the well was drilled with CwD and PDC drill-out technology. Included in this paper are the application, technologies involved, results and lessons learned. It also summarises the performance witnessed on the second well using the same methodology.
Case Study--Field Implementation of Automated Torque-and-Drag Monitoring for Maari Field Development
Authors: Niedermayr M. , Pearse J. , Banks M. , Thonhauser G. , Zoellner P. 
Published: February 2010

Abstract
This case study presents a novel approach to capturing torque and drag trends real-time while drilling complex and extended reach wells. Data processing algorithms automatically process rig sensor data. They recognize current rig operations and log drill string torque and drag parameters. Data is automatically collected, presented and shared without any exposure to human error or interpretation in data recording, allowing engineered real-time and longer term decisions to be made with accurate and consistent data. The tool relies on updated torque and drag models but otherwise works without further input or drilling process interruptions and it does not require extra personnel on or off-site.
The main purpose of the new system is to confirm hole condition. The system acquires and displays well documented field and operation specific drag values. On Maari this information has been used to make strategic decisions on mud systems, critical casing runs, running strings, trajectories, accessible targets and contingency planning.
The paper outlines the monitoring process and system support. It will present actual results and detail how its use has aided planning, drilling and logistics. Field data will be presented in support of the examples listed below. minimized back-reaming during drilling connections and overall reduced hole cleaning effortsreal-time decisions on location, need and quantity of HWDPs or DCs in the screen running strings, avoiding rig time to pick up tubulars from deckconfident decisions to swap from synthetic to water-based mud in hole sections that industry experts have previously classified as ‘border line casing floatation area’elimination of synthetic-based mud in intermediate sections, the overall environmental impact of the drilling campaign has been drastically reducedplanning a new extended reach well based on monitoring results has allowed appraising and potentially producing off structure reserves otherwise strandedthe field application has also proven 24/7 support and maintenance of equipment far off service provider home base
The case study also outlines technical difficulties encountered and how these were addressed during product testing and its first commercial field application.
Characterization of Sampling While Drilling Operations
Authors: Villareal S , Pop J , Bernard F , Harms K , Hoefel A , Kamiya A , Swinburne P , Ramshaw S 
Published: February 2010

Abstract
Although formation pressure-while-drilling (FPWD) tools have been introduced relatively recently the service is well accepted not only for its application to drilling optimization but also for reservoir characterization, especially in developed reservoirs. The next step in the progression of reservoir-related services to the drilling environment is clearly the acquisition of formation fluid samples while drilling. The while drilling environment, however, poses several potential challenges (and opportunities).For example: when should one sample, immediately after drilling the formation when the invasion is shallowest, or, after some time when the mud cake is more mature?; what is the effect of circulation rate on mud cake integrity?; and so on.
The first part of the paper describes a sampling-while-drilling (SWD) tool which is comprised of the following components: a probe module; a pumpout module, which has contained within it fluid property sensors, including a resistivity cell and a ten-channel optical spectrometer; a multi-sample module; and, a power generation module, consisting of a dedicated mud turbine and alternator which provides the required pumping power to the sampling tool.
The second part of the paper is devoted to the description and analysis of a series of tests which were performed to characterize sampling while drilling operations. In particular, the following aspects were studied for their effect on sampling efficiency and sample contamination: time after bit; mud circulation rate; ceasing and resuming pumping operations as a means of mitigating sticking risk during protracted pumping operations; and, captured sample integrity under drilling conditions.
All formations tested contained water as the formation fluid and the well was drilled with a water-based mud. Samples were acquired at multiple times during a single station and at multiple stations during the sampling operation in order to evaluate the effect of the test parameters on sample contamination and clean-up. To aid in the laboratory contamination analysis the mud was doped with bromine and iodine tracers. In addition, a water soluble blue dye was mixed with the mud to allow real-time monitoring of clean-up during pumping by means of the optical spectrometer. A wireline sampling tool was run after the while drilling tests were completed in order to compare the performance of the two sampling tools. In addition to the usual LWD logs, gamma ray, array resistivity, density-neutron and spectral gamma ray, a shallow array resistivity tool was run to quantify the extent of invasion at various times during the drilling/sampling operation.
The principal conclusions derived from the series of tests conducted are, that present-day sampling technology can be made to survive and operate effectively under drilling conditions and that there appear to be advantages to acquiring samples soon after drilling a formation.
Continuous Motion Rig: A Step Change in Drilling Equipment
Authors: Grinrod Mads 
Published: February 2010

Abstract
This paper outlines the technology and benefits of the continuous motion rig concept. This step change in drilling facilities technology is achieved through automation allowing any type of tubular to be pulled or run into the well without frequent intermittent stop in movement.
The continuous movement is enabled by mounting two lift systems in the derrick. The two systems work together in sequence comparable to pulling or lowering a rope continuously with both hands instead of working with only one hand. To be able to work a string with threaded joints in a continuous fashion up or down in the well the joints must be disconnected or connected while in continuous vertical movement. This implies that slips and tong must be mounted on each of the lift systems, taking string weight while connecting or disconnecting the coupling.
The basics and challenges of this system are outlined in the paper. When working in a continuous manner it is shown that even a slow continuous speed results in significant efficiency increases. A continuous slow drill pipe pulling speed of 0,5 m/sec results in tripping 1800 m/hr or app. 64 stands of 28m (app.90 ft) stands per hour. Doubling the speed to 1 m/sec, corresponding to app.peak pulling speed of today's drawworks in low gear, results in tripping speed of 3600m/hr.
One challenge of the system is to have technology in the vertical moving tongs to break connection and spin out in short enough intervals to avoid excessive height in the derrick.
Since string load is taken by the lift system off well center bending loads will be transferred to guide beams which must be given proper strength.
Other benefits of the continuous movement is minimizing problems normally connected with surge and swab effects due to lifting drill pipe out of slips and increasing pulling or lowering speed to peak and then brake down and stop. Further the problem of stuck pipe or casing caused by stop for connection is eliminated.
Gyro Guidance Techniques and Telemetry Methods Prove Economical in Onshore Multi-Well Pad Drilling Operations in the Piceance Basin
Authors: Garza Travis , Wimberg James , Woolridge Trevor , North Ezra , Beattie Keith 
Published: February 2010

Abstract
Wellbore collisions and accurate well placement are major concerns in Chevron U.S.A. Inc.’s multi-well pad drilling operations in the Piceance Basin in Colorado. Up to 24 wells are drilled from a single pad with two rows of well slots. As a result of the high well slot density, gyroscopic survey systems must be run during kickoff operations in most wells due to magnetic interference.
Several methods of obtaining high accuracy rate gyroscopic (gyro) survey data have been employed, including:
Rate Gyro single-shot surveys run on wireline; Gyro-While-Drilling (GWD) system incorporated in the Measurement-While-Drilling (MWD) string communicating with mud pulse telemetry; and GWD system incorporated in the MWD string communicating with electromagnetic (EM) telemetry.
This paper analyzes the performance of the three survey methods with respect to safety exposure, rig time, cost of service, equipment logistics, personnel requirements and operational performance. Field data is analyzed from more than 100 wells. This represents the largest database known by the authors for comparison of these service types presented in published literature.
Results indicate a solid justification for incorporating the gyro in the MWD string for the following reasons:
Saves rig time by eliminating the separate wireline; Decreases safety risk exposure by eliminating wireline operations; Minimizes risk of stuck bottomhole assembly (BHA) due to static operations during wireline surveying; EM technology when combined with the gyro creates an accurate, efficient, and reliable surveying system when compared with mud pulse-conveyed telemetry; Improved drilling control resulted from being able to steer continuously while drilling with the gyro in the MWD string; and Accurate well placement has decreased well collision exposure with no wellbore collisions to date.
Incorporating rate gyro systems in the MWD string while drilling has proven economical in the more costly offshore environment for a number of years (Eaton 2005). Applying the technology successfully to less expensive onshore projects can increase efficiency and bring additional benefits in reduced logistical requirements and safer operations.