bluuebunny/crossref_metadata_2025_split huggingface dataset:
Exploration Drilling in the Russian Far East: 2 Years of Experience and Learning Offshore Sakhalin Island
Authors: Thorogood J. L. , Hogg T. W. , Kalshikov A. G. 
Published: December 2007

Abstract
An exploration well drilled by a joint venture between Rosneft and BP in the summer of 2004 was the first success after a long period of no exploration activity. It represented a step out into a new and untested exploration play.
Wells in Sakhalin involve a permitting cycle that lasts for 7 months and a logistical supply chain that extends 3,500 miles back to Singapore, Figure 1. The sea ice-free weather window lasts from late June until mid-November, with severe storms building from September onwards. Environmental restrictions stipulate that all mud and cuttings from below the 30" conductor, even though the well may be drilled with a water-based mud, cannot be discharged to the environment and must be recovered for disposal. Figure 1Regional setting showing Sakhalin in relation to the mobilisation point of Singapore
The team overcame a wide range of organisational, logistical, regulatory, environmental and technical challenges to drill the well in the summer of 2004. Despite the highly compressed schedule, the operation was conducted with no harm to people or damage to the environment. The lessons learned were consolidated and formed the basis for a successful season in 2005 with a different rig.
ROP Enhancement in Ultrahard Rock
Authors: Roehrlich M. , Belohlavek K.-U. 
Published: December 2007

Abstract
Drilling the Middle and Upper Bunter formation (Triassic) in North-West Germany has been a challenge for nearly 40 years. The Bunter is a hard and very abrasive formation, typically in a depth range of 8000ft – 12500 ft. It consists of layers of quartzitic sandstone and silificated claystone. Low ROP and extremely high wear of tools is characteristic for drilling this formation. To improve the performance and decrease cost/ft, intensive research was done in the past.
This paper deals with the results of the analysis of historical data and the development of bits, motors and other BHA components to one system. This BHA system is to enhance ROP and reduce trips due to dull bits or BHA and drillstring failure. To date, 15 runs of these improved BHA systems have been performed. Performance data have been analyzed and will be presented to document improvements achieved. An outlook for future opportunities will be given.
Drilling the Bunter is still time consuming and expensive. In the past, typical ROPs in 12 1/4" sections were 3 – 6ft/hr. Back in the 1970's and 80's, 15 to 20 insert bits were required to drill the section and reaming was necessary due to under-gauge bits. Both, low ROP and short bit life contributed to significant total section times. The combination of new impregnated bits and new downhole motors together with improved hydraulics in larger ID drillpipe were the basis for improvement. Today, with an optimized system, ROPs of 8 – 19 ft/hr have been achieved. In addition, it is now possible to drill the bunter section in one trip. Two world records, for single footage and cumulative footage of an impregnated bit are held within EMPG (German ExxonMobil affiliate) in this section.
In recent and upcoming wells, new motor developments are tested to repeat latest successful results and to further improve ROP. In addition, a different bit design will be run for further potential ROP enhancement. Significant reduction of section time justifies the application of more sophisticated and more expensive tools on German land rigs to further reduce cost/ft.
Proven Commercial Implementation of Second-Generation Integrated Remote Drilling Operations Center
Authors: Nathan E. , Dagestad J. O. , Lilleng T. , Pedersen T. 
Published: December 2007

Abstract
One recent management trend is the establishment of onshore operations centers by oilfield operators that are currently developing offshore assets. Unfortunately, the formation of such a center has typically been a niche activity within many companies and, as a result, some may fail to consider the lessons learned from earlier operation center failures. It is also vital that those attempting to develop such a center make sure the center's purpose functions within the industry's overall framework. While these centers have often delivered, with varying degrees of success, on their anticipated benefits such as faster decision-cycle time, better, more informed decisions and reduced POB, robust business and organizational models are necessary to ensure these efforts' long-term viability.
As part of a long-established business partnership, Norsk Hydro and Baker Hughes INTEQ have recently implemented changes to the industry's longest continuously running remote drilling operations center. Supporting some of the Norwegian Continental Shelf's most technologically challenging drilling operations, the center is contributing to improved financial performance, reduced POB, enhanced service quality and supporting work process changes within both organisations.
The revised model has been implemented as the ‘normal’ service delivery channel for five drilling operations supported by the BEACON center on a 24/7 basis and routinely operate advanced technologies such as formation pressure testing while drilling, deep reading resisitivity and azimuthal imaging services.
This paper will outline the technical and commercial models that have been developed, provide insight to the challenges encountered and achieved successes.
Drilling and Completing Difficult HP/HT Wells With the Aid of Cesium Formate Brines— A Performance Review
Authors: Downs J. D. , Blaszczynski M. , Turner J. , Harris M. 
Published: December 2007

AbstractConventional drilling and completion fluids containing weighting solids or hydrocarbons or halide brines can create problems with hydraulics, well control, well integrity and well productivity in HPHT operations. The negative influence of conventional fluids on drilling and completion operations can be sufficiently serious to compromise safety and degrade the economics of challenging HPHT field developments.Formate brines have been developed specifically to provide improved drilling and completion fluids that are free of the troublesome components found in conventional fluids and therefore better suited to meet the needs of oil companies involved in difficult HPHT well constructions.Formate brines have been successfully used as reservoir drill-in, completion, workover and suspension fluids in more than 130 HPHT well construction operations over the past 10 years. These applications have included 100 cases in which high down-hole pressures have necessitated the use of cesium formate brines for well control purposes.Some 15 applications of cesium formate brines to date have been HPHT reservoir drill-in operations in high angle wells where operators considered that conventional fluids could create a safety risk and adversely effect project economics. We review the published information on the field performance of the cesium formate brines in HPHT applications, and conclude that the novel benefits of the technology that were first promised some 15 years ago during the early product development phase have now been fully validated.
Andrew Low-Cost Drilling—Teamwork, Technology, and New Working Practices Extend Field Life
Authors: Sawaryn S. J. , Qureshi R. H. , Trythall R. J. B. , Bourne L. , Price B. , Telford C. 
Published: December 2007

AbstractAn innovative two-well Low Cost Drilling (LCD) programme has been executed to exploit small, un-drained oil targets in the Andrew field. The wells have been drilled with 10% fewer offshore drilling crew, enabling critical back-to-back inspection and fabric maintenance to continue. Reserves targets have been met and costs reduced by 35%, allowing access to other smaller targets and extending field life.Three questions needed to be satisfied throughout the program. Is the oil there; can we access it cost effectively and can the platform accommodate the work? In 2004, we accepted the challenge to identify and develop these targets and embarked on a 3-point program to: (1) Better define oil targets using 4D seismic and Top Down Reservoir Modelling (TDRM) techniques to address uncertainty; (2) Minimize offshore drilling support by using an Onshore Operations Centre (OOC). Only 80 beds are available for managing the delivery of all aspects of the business. (3) Minimise drilling cost through sidetracking, de-scoping and executing preparatory well work prior to full rig mobilization. Highlights include drilling the 6" hole section in a single run using agitators to maximize ROP by maintaining WOB transfer and simplifying completions to use pre-drilled liners, isolating the production zones using swell packers.This success has been achieved through innovation, technology and adopting industry best practice, with meticulous planning and outstanding teamwork between operations, subsurface and drilling, both onshore and offshore.
A Re-examination of Drillpipe/Slip Mechanics
Authors: Paslay P. , Pattillo P. D. , Pattillo II P. D. , Sathuvalli U. B. , Payne M. L. 
Published: December 2007

Abstract
Current models of slip crushing treat the rotary slip as an axisymmetric wedge that generates an axisymmetric radial load on the drillpipe lateral surface. However, recent tests on strain gauged drillpipe specimens suggest that this model does not adequately capture the mechanical response of the drillpipe. The tests show that drillpipe response is a complex and non-axisymmetric function of slip geometry, friction between the slip and the bowl in the rotary table, and the mechanics of load transfer between the slip and drillpipe.
This paper presents a new model of slip behavior that represents the slip system as a series of line loads. Analysis of the suspended tubular under these forces and axial tension leads to a limit load that characterizes slip crushing. A corollary of this analysis is the minimum slip length required to support a given axial tension.
The Effect of Friction on Initial Buckling of Tubing and Flowlines
Authors: Mitchell R. F. 
Published: December 2007

Abstract
The introduction of friction into the analysis of buckling stability causes problems. For sliding friction, the friction force is fully developed for small lateral motion, while the destabilizing effect of the axial force is proportional to the lateral motion. Because the sliding friction force develops so rapidly and destabilizing effects develop so slowly, buckling is essentially impossible.
But we know that pipe buckles with friction! In conventional analysis, the only possibility for buckling is to have an initial non-zero lateral displacement, so that the axial force contribution may exceed the fully mobilized friction force. This initial displacement cannot normally be accurately estimated, so the force needed to buckle pipe with sliding friction is essentially unknown.
A cylindrical pipe has another possible mode of lateral displacement. Instead of sliding, the pipe can roll. In this case, the friction force developed is static friction. Static friction may take on any value between zero and the peak static friction value, where the value of the static friction is usually determined from a balance of known forces in the problem of interest. Here, the magnitude of the static friction is determined from a balance of torsional forces on the pipe. The key fact is that the friction force develops gradually, so we may determine a critical buckling force in the traditional sense.
The introduction of axial torque adds further complications to the buckling analysis. This paper develops a comprehensive model for pipe with axial forces and torque, and then develops the critical buckling loads for three cases of interest. The first case corresponds to the pipe in the wellbore, as investigated by Dawson, Paslay, He, and Kyllingstad. The second problem looks at a pipe lying on a flat plane, as a pipeline on the seabed. In both cases, a critical buckling load is determined for pipe whose lateral motion is constrained by friction. The third case finds the critical buckling load for rotating pipe. Several sample calculations are performed to illustrate the importance of friction forces in the stability of tubing and in the stability of seafloor flowlines.
Ringhorne Development: Technologies Applied in Extended Reach Drilling—Successes, Failures, and Communicating Risks
Authors: Musaeus N. 
Published: December 2007

Abstract
This paper describes some of the key drilling technologies used in the well construction of long reach and extended reach wells as part of initial field development of 6 reservoirs from the Ringhorne platform. Difficult drilling conditions exist due to extended drilling targets through highly reactive shales and require Non-Aqueous Fluid (NAF) drilling fluids at elevated mud weights. The Ringhorne development was made possible by using a combination of latest drilling technologies for extended reach drilling and an adequately designed rig to ensure success. In order to mitigate the resultant tight drilling margins, a number of optimizations impacting well designs and field operating practices were implemented. Among these have been latest applications of the newest Rotary Steerable tools, refined directional surveying and anti-collision practices, use of hole openers and underreamers to mitigate tight drilling margins, surveillance practices, use of low viscosity drilling muds, lost returns response practices, Logging While Drilling (LWD) advancements for geo-steering and casing installation techniques.
The Ringhorne development is a project example where more of a project's risk is being carried in the well construction phase since the development is on the current outer edge of drilling technology. The structured well planning, design and review processes will be summarized and explained to illustrate how these were used both to balance technology application and communicate risks to stakeholders.
Planning and Detailed BHA Vibration Modeling Leads to Performance Step Change Drilling Deviated 24-in. Hole Section, Offshore Norway
Authors: Grindhaug G. , Elsborg C. 
Published: December 2007

Abstract
This paper presents a case study of the detailed planning and BHA modeling used to improve performance in drilling deviated 24 inch hole sections and its implication to the on-going Ringhorne extended-reach-drilling (ERD) program. The paper describes the planning; modeling and results of the 24 inch drilling performance achieved in the longest extended reach well drilled to date in the Ringhorne Development, Offshore Norway.
Ringhorne wells usually kick-off below the 26 inch conductor in 17-1/2 inch hole building angle from vertical to 65 degrees where 13-3/8 inch surface casing is typically set. This is not the case for the development with extended well targets where it came necessary to upsize the casing program with 18-5/8 inch surface casing. This requires a 24 inch deviated hole to be drilled from approximately 300 meters measured depth (mMD) to 70 degrees by 1000 mMD with casing point at approximately 1600 mMD to enable drilling to the reservoir targets at 1700 – 2000 meters true vertical depth (mTVD).
The first 24 inch section was drilled using a 17-1/2" polycrystalline diamond (PDC) bit, rotary steerable system (RSS) and PDC hole-opener. Severe vibration problems were experienced while drilling through the Utsira sands near the base of the section causing a rotary steerable tool failure. This led to loss of angle and slightly earlier casing point than planned. The next 24 inch section was drilled using a two-run strategy including a 17-1/2 inch RSS to total depth (TD) before picking up a 24 inch hole-opener in a separate run. The first hole-opener run twisted off above the bottomhole-assembly (BHA) while drilling the massive Utsira sandstone and three subsequent hole opening runs were pulled due to poor performance resulting in a tapered casing string to be set.
Because of the poor BHA performance and the associated drilling problems, the operator and the service company conducted an extensive analysis of offset drilling performance followed by a thorough modeling study to ensure success in drilling the long reach 25/8 C-12 (C-12) well from the platform. Due to the complexity of the well, no deviation from the well path could be tolerated and the casing shoe had to reach the planned depth. Time and depth based data, formation information and vibration measurements from the offset wells were evaluated using analytical software. These results were used to analyze various BHA's for stability.
This investigation led to the development of a stable BHA configuration and selection of optimum bit properties, recommendation for parameter combinations and response plans for the formations encountered. A plan was developed that focused on drilling practices and parameter adjustments according to the formation. The result was a significant reduction of vibration that enabled the rig crew to successfully drill the 24 inch section following the well path and run the 18-5/8 inch casing to planned TD without incident.
The Next Generation of Sakhalin Extended-Reach Drilling
Authors: Viktorin R. A. , McDermott J. R. , Rush R. E. , Schamp J. H. 
Published: December 2007

Abstract
Six of the ten longest reach wells in the world have been drilled in Chayvo field on Sakhalin Island. Significant learnings have been gained from these wells and have been applied to the remaining wells to reduce cost and improve well performance. The learnings are discussed in this paper.
The most significant improvement in the Chayvo wells involved redesigning the completion. Initial completions were cased, cemented and perforated on coiled tubing to achieve a low-skin completion with zonal isolation. Alternative completion methods were evaluated after experiencing problems with production liner cementing and coiled tubing perforating. The revised completions incorporate stand-alone screens (SAS), predrilled liners and swell packers to achieve a low damage, sand free completion with zonal isolation.
Initial wells required extensive backreaming to make connections and trips. Bit designs, bottom hole assembly (BHA) configurations and operations practices were modified to minimize the amount of backreaming, improve overall rate of penetration (ROP) and achieve a "One-Pass Trippable Hole". Implementation of ExxonMobil's Fast Drill Process1 (FDP) was incorporated to achieve additional improvements in ROP.
Another learning was the importance of rotary steerable system (RSS) reliability since eliminating trips to replace the tools were a primary driver in overall performance. Rotary steerable systems were improved by evaluating failures, redesigning downhole components and implementing an incentive contract based on run time. Understanding and managing the causes of vibration using surface and downhole vibration measurement tools also contributed to increased rotary steerable life and higher overall ROP.
The evolution of Sakhalin bit designs was driven by a variety of factors. Initial bit design focused on steerability and instantaneous ROP. Second generation bit features were designed to reduce overall drill string torque by reducing micro-tortuosity and bit reactive torque in the 8-1/2 in. hole section. The most recent generation of bit designs have experimented with extra long gauge lengths to reduce bit darting and excessive vibrations in hard stringers while maintaining high ROP capability.
The first generation of casing installation employed full or partial flotation to run the 13-5/8 in. casing, 9-5/8 in. casing and 7 in. liners. On site engineering surveillance and calibration of torque and drag models enabled the use of conventional mud-filled casing runs on the subsequent 13-5/8 in. casing and 7 in. liners. Running conventional mud-filled strings reduces the risk of casing collapse and decreases running costs.
Achieving Technical Limits: Expanded Application of Real-Time Pressure-While-Drilling Data Helps Optimize ROP and Hole Cleaning in Large-Diameter, Directional Intervals
Authors: Lapierre S. , Courville G. , Song J. 
Published: December 2007

AbstractIn large-diameter directional intervals, high instantaneous rates of penetration (ROP) must often be sustained in order to achieve directional objectives. The combination of the large diameter hole, high ROP, and high inclination can present a number of challenges for effective hole cleaning. Nonproductive time (NPT) associated with pack-offs, lost returns and stuck pipe can result if the proper balance between ROP and available hole-cleaning capacity is not achieved.Conventional practices for ensuring adequate hole cleaning when drilling with conventional directional assemblies include incorporating additional circulation time prior to making connections. However, if the additional circulation time is inadequate, the risk of pack-off increases significantly. If the additional circulation time is excessive, the operator is not able to drill at the technical limit of efficiency. Conventional practices also include monitoring real-time equivalent circulating densities (ECD) from pressure-while-drilling (PWD) tools to gauge hole-cleaning effectiveness and to identify pack-offs. Unfortunately, the abrupt nature of a pack-off and the rapid increase in ECD that ensues provide little forewarning, resulting in only a limited ability to minimize NPT.An expanded application of real-time PWD measurements can be used to optimize ROP and hole cleaning, and so enable the operator to maintain the technical limit of efficiency more effectively. Based on the use of real-time equivalent mud weight (EMW) measurements acquired during ordinary pump cycles, this technique involves new methodologies to identify hole-cleaning deficiencies earlier in their development than currently possible through conventional real-time ECD monitoring. As a result, the operator can manage hole-cleaning improvements based on direct determination of hole-cleaning efficiency.The effectiveness of this technique is demonstrated in a comparison of two similar wells drilled in the East Breaks (EB) area of the Gulf of Mexico by Kerr-McGee Oil & Gas Corporation. On "Well A", EB 688 #8, conventional practices were used to drill 2,254 ft of 17.5-in. hole to 45° inclination in 3.4 days. On "Well B", EB 686 #2, the expanded PWD application was employed to drill 3,107 ft of 20-in. hole to 53° inclination in only 2.5 days. This paper describes the details of the expanded PWD application and results from its field implementation.