bluuebunny/crossref_metadata_2025_split huggingface dataset:
Managing a Complex Deepwater Deposit through Advanced Simulation Technologies: Balder Field, Norway
Authors: Wang Gann-Shyong , Rossen Robert H. , Hjellbakk Andor , Sun Michael C. 
Published: December 2007

Abstract
The Balder Field is located in the Norwegian sector of the North Sea, about 190 kilometers west of Stavanger, Norway. The field consists of 8 separate hydrocarbon accumulations (mostly in mounded structures) in three separate stratigrahic units of Paleocene and Early Eocene age. The field has been on production since September 1999. During the production history, it has been observed that the interaction between the producing reservoirs, the Paleocene aquifer and the Eocene gas cap plays a significant role in controlling the overall field performance.
A full-field reservoir simulation model was developed for the Balder Field for reservoir management and surveillance. The model was built using a state-of-the-art reservoir simulator developed by ExxonMobil. Application of advanced features in this new simulator has significantly improved the accuracy of the model and the efficiency of modeling work. Key features highlighted in this study are: Gridding to faults and wells allowed more accurate representation of fluid movement without a significant increase in model sizeFlexibility of unstructured gridding allowed rapid generation of models with grid refinement over different reservoir regions to improve the efficiency of history matching efforts. This feature has the benefit of focusing history matching on a particular reservoir while still representing the correct interaction with other producing reservoirs in the field. A total of eight models of this type were built during the his tory matching phase of the study.Feedback between Geologic and Flow Models resulted in rapid cycle time (less than 1 day) for a revised geologic model to be carried through to complete simulation. Quick feedback between geologic and flow models improves interaction between geoscientists and reservoir engineers, hence the quality of history matching.Coupled wellbore/reservoir simulation resulted in an accurate representation of hydraulics in a subsea production system.
Control-Volume Distributed Sub-Cell Flux Schemes for Unstructured and Flow Based Grids
Authors: Edwards Michael G 
Published: December 2007

Abstract
New locally conservative flux continuous formulations are presented for general grids comprised of quadrilateral and or triangular grid cells. The schemes guarantee that a symmetric positive definite discretization matrix is obtained for both an arbitrary polygonal control-volume distributed formalism and a new sub-cell distributed formalism.
Monodiameter Drilling Liner – from Concept to Reality
Authors: Campo Don , Williams Charlie , Filippov Andrei , Cook Lance , Brisco David , Dean Bill , Ring Lev 
Published: December 2007

Abstract
Many in the oil and gas industry initially viewed the idea of a monodiameter well as a radical concept. But with the recent success of a field trial well, the monodiameter well has moved from concept to reality and is now a viable well construction process.
The monodiameter well is a breakthrough in the oil and gas industry. This technology allows multiple strings of the same size drilling liner to be installed in a well without a decrease in internal diameter (ID). The elimination of reducing ID is accomplished by an over-expansion of the monodiameter drilling liner and the base casing in the overlap section.
The monodiameter well construction process involves installing a monodiameter drilling liner below the casing and expanding it and the overlap. The resulting ID will allow additional monodiameter drilling liners to be installed and expanded without reducing the ID experienced in a standard telescoping casing program. Thus the expansion of the monodiameter liner creates a single ID.
The benefit of the monodiameter well construction process is that it reduces total drilling costs, especially in challenging areas, and enables operators to maintain the well's optimum completion diameter.
This paper briefly discusses the monodiameter drilling liner's transition from concept to reality, and focuses on the field installation of the monodiameter drilling liner. This paper also discusses the potential cost savings of using the monodiameter well construction process.
Completion of an Underbalanced Well Using Expandable Sand Screen for Sand Control
Authors: Cuthbertson Robert L. , Green Annabel , Dewar John A. G. , Truelove Brian D. 
Published: December 2007

Abstract
Recent technology advancements now make possible the deployment and expansion of Expandable Sand Screen (ESSTM) into an underbalanced well. This accomplishment opens up the door to bringing the well-established benefits of UBD into the area of less consolidated sandstone reservoirs that require some form of sand control. A likely target for these combined services is the deepwater offshore arena where undamaged high rate producers are required to meet critical and demanding economic criteria.
Key to achieving this desirable end result is the development of a new full-bore Downhole Deployment Valve (DDV) that serves as a subsurface lubricator valve for running the unexpanded ESSTM safely into the live UBD well. Additionally, new improvements in the compliant ESSTM and associated running and expansion tools result in the largest possible internal screen diameter post expansion. The elimination of gravel packs and conventional sand screens results in significant production improvements over alternative solutions. By adding the advantage of reduced filtrate invasion and solids plugging of the sand face through drilling and completing the well underbalanced, both of which impair the well's ability to achieve maximum productivity or full depletion of the potential reserves, an optimum solution is achieved. The result: maximum flow rates, effective sand control and capture of a higher quantity of reserves.
Expandable Drill Bit Provides New Method of Drilling Increased Diameter Hole
Authors: Brown Martin D. , Gledhill Andrew D. 
Published: December 2007

Abstract
It has long been recognised within the drilling industry that the ability to drill an increased diameter borehole, having passed through a restricted casing and/or tubing diameter, can provide significant advantages. Among these is the ability to incorporate novel well construction techniques, using both solid and/or expandable tubulars, as well as Drilling with Casing possibilities, in which the casing is run immediately behind the bit. The opportunity to successfully incorporate these new techniques can thus enhance well design to yield significant economic and well control gains.
Current techniques for drilling such increased diameter holes, such as bi-centered bits and under-reamers, have limitations on their ability to expand, whilst at the same time compromising the cutting structure presented to the formation. Additional limitations include limited reaming and back reaming capabilities, as well as non-uniform directional response. This can lead to well construction problems and reduced drilling performance. One embodiment of the technique of Drilling with Casing requires a bit which can be retrieved through the existing casing string. To achieve this and to maximise drilling performance requires a device with a formation cutting structure, indistinguishable from a standard PDC drill bit but capable of being withdrawn through a restriction significantly smaller than the borehole size just drilled. This concept leads to the possibility that a viable solution to the task of drilling increased diameter holes could be a bit that offers substantial expansion capabilities while still presenting full cutting structure to the formation.
In this paper the authors will discuss the earlier problems and solutions and then present a new approach with an "Expandable Drill Bit". They will discuss the design concept, development and prototype construction of such a bit and will also present details of the successful field trials and the minor design changes that resulted from them. They will conclude that use of an "Expandable Drill Bit" is a viable tool for a variety of drilling applications.
Abandonment of the Hutton TLP Wells
Authors: Plumb A. B. , Stewart A. , van de Laar J. , Milton P. 
Published: December 2007

Abstract
This paper reviews the wells abandonment aspects of the Hutton TLP decommissioning project, highlighting lessons learned during the project to achieve the early sailaway date in 2002.
The Hutton Field produced via a tension-leg production and drilling platform (TLP) located in the East Shetland Basin, producing from 32 oil producers and water injection wells.
The TLP was a floating structure with the wells utilising a subsea wellhead system tied back via rigid 9.5/8" production risers, terminating on the wellhead deck with a Tubing Head Spool (THS). The risers were supported by a tensioning system from the TLP. The lower completion tubing was supported at c.1000 ft MD BRT by use of a 9.5/8" subsea hanger or annular packer, with the final 1000 ft of 5.1/2" tubing being landed in the THS. The THS and hanger were topped with a "dry" 5000psi FMC Xmas Tree.
Due to the decreasing production and increasing water cuts of the Hutton wells from 2000 onwards, continued use of the TLP as a commercial proposition was under continuous review. Through late 2000 and early 2001, contingency plans were worked up for well abandonment and the poorer-performing wells on the field with no sidetrack options were identified for early abandonment. Full well abandonment commenced in July 2001 with a target date of mid-2002 for Hutton TLP sailaway.
In order to fast-track the well abandonments, a phased approach was employed, allowing concurrent operations, achieving a considerable time saving over a more conventional approach for such technically challenging wells. Given the number of wells and the repetitious nature of the work, a technical limit approach was also adopted to ensure that lessons learned from the work were quickly integrated and fed back into the ongoing project.
Drilling Contractor Safety Management System
Authors: Blank Bob , Prewitt Annette 
Published: December 2007

Abstract
A drilling contractor exists to provide the personnel, equipment and services that the market desires. In addition to these tangable assets, the successful drilling contractor also requires a reputation for safety and operational performance. All five of these assets must be effectively managed for a drilling contractor to survive.
This paper will cover the formal management system created and implemented by one offshore drilling contractor to manage safety. An overview of the Safety Management System (SMS) and its most important components are provided.
Development and evolution of the system into one holistic system that meets the safety, environmental and regulatory needs of the company's worldwide fleet is discussed.
Also covered will be the steps taken to ensure the workforce's knowledge of and participation in the system and the steps taken to monitor and continueously improve the system's effectiveness.
Real Time Monitoring of Hole Cleaning on a Deepwater Extend Well
Authors: Martins A. L. , Villas-Boas M. B. , Taira H. S. , Aragão A. F. , Amorim R. A. F. , Galeano Y. D. , Bove A. , Waldmann A. T. A. 
Published: December 2007

Abstract
This paper details the first utilization of a cuttings flow meter device on a floating platform. This device was installed at platform PETROBRAS – X during the drilling of an extended horizontal well (5211 m total depth) at 1212 m water depth. Since hydraulics and cuttings removal were major issues during drilling, the CFM concept proved to be an important tool to evaluate hole conditions. A discussion on the adequacy of hole cleaning operational procedures and on the uncertainty in results evaluation is also included.
Key Initiatives Improve Production Testing Performance, Deepwater West Africa
Authors: Schuberth Paul C. , Garcia Enrique M. , Walker Mike W. , Akers T. Jay 
Published: December 2007

Abstract
Since 1996, ExxonMobil has conducted an extensive deepwater exploration / appraisal program in West Africa. In an effort to achieve improvement in production testing performance, ExxonMobil's West Africa Deepwater Drill Team pursued key initiatives to deliver quality well test operational results. These initiatives included performing effective long-term and near-term planning, highgrading equipment quality control and inspection practices, making appropriate use of selective new technology, enhancing standardized procedures by capturing lessons learned and best practices, performing rig-site engineering supervision of production testing operations, and communicating captured follow-up recommendations to service contractors. To execute these continuous improvement initiatives, a single dedicated test engineer was assigned to plan and oversee all West Africa well testing operations. As a result of this increased focus, the average non-productive time (NPT) per test has been reduced from approximately 30% to 6% and the overall test time has been reduced by about 40%. The methods and resources used to achieve these improvements are discussed in detail in this paper.
A New Approach for Running Production Casing from Semi-Submersible Rigs on Highly Deviated Wells
Authors: Rae G , Williams H , Hamilton J 
Published: December 2007

Abstract
This paper outlines a new technique for running production casing from semi-submersible drilling rigs on highly deviated wells and was used for the first time on the Captain Field, UKCS, operated by ChevronTexaco. The technique, which incorporates selective-flotation techniques, has been used successfully on three subsea wells to date. This is believed to be the first employment of the above technique on semi-submersible rigs.
Drilling HP/HT Wells in Bosque Field, Venezuela - The Aloctono Block Challenge
Authors: Avila J. C. , Zerpa E. , Rojas L. , Salas J. G. 
Published: December 2007

Abstract
Bosque field presents some of the most challenging conditions for drilling, in Venezuela. The sandstone reservoir can be found below 20,000 ft, pressures exceed 12,000 psia, and temperatures are over 300°F. The main characteristic of this area is a great inverse fault in the north-south direction called Pirital's landslide. Because of this landslide, Cretaceous formations overlie a Miocene formation. These have been called the Aloctono block. So the geology is very complex, containing faulted structures, large dips, and hard and abrasive rocks. Drilling operations struggle to overcome numerous problems, such as low rates of penetration (ROP), wellbore instability, lost circulation, and trajectory deviation.
Since the discovery in 1988, these obstacles have seriously affected the field's profitability. To optimize the reservoir management strategies, the operator Petroleos de Venezuela S.A. (PDVSA) commissioned a delineation and development project. A fundamental issue has been to improve drilling performance because of its notable influence on field development. To achieve this goal, a multidisciplinary drilling team was formed, involving not only drilling experts but also personnel from other areas, such as production and reservoir engineers, geophysicists, geologists, and petrophysicists.
To construct the first project's well, the team selected the well location by seismic 3D data, combining the reservoir objectives and the best conditions for drilling, determined the bottomhole assembly (BHA) with best vertical response by drillstring simulation, and used near-balance drilling and 6⅝-in drillpipe to increase the ROP. These practices led to reaching a total depth of 21,199 ft, an ROP increase of 25% in the Aloctono block, and the largest Aloctono thickness drilled, 12,850 ft, to reduce the drilling time and the well-construction investment. A key factor was the 9⅝-in casing run, which required a new design and a detailed analysis of the rig and tools capabilities because of being the heaviest casing ever run in Venezuela (maximum tension of 1.25×106 lb).
Brae Field Extended Reach Drilling - A Case History
Authors: Lumsden George C. , Parker Jeff R. 
Published: December 2007

Abstract
This paper describes the experiences from drilling an extended reach well in February 2002 from a North Sea production platform constructed to develop a gas condensate reservoir, into an adjacent mature black oil field that had been previously developed with subsea facilities. The background to the project meant that a new conventional subsea type well tied into the existing infrastructure would not be able to deliver some of the key elements in developing reserves from the field.
Conceptual drilling engineering studies indicated that an extended reach well would be viable with a relatively minimal upgrade to the existing platform drilling facilities. The experiences of numerous other ERD (extended reach drilling) projects are well documented and whereas most issues are described as "good drilling practices" and are aligned company best practices, other issues were new to the organisation and required thorough review before deciding whether utilise that experience. Given this was the first such type of well for the company many of these issues were encountered.
HES (Health, Environmental and Safety) issues were particularly relevant to this project given the magnitude of the well, the human challenges with using unfamiliar equipment, and the environmental regulations governing the handling of drill cuttings.
Ultimately the project was sanctioned and after the numerous problems that were encountered, including three sidetracks and two lost BHA (bottom hole assemblies), the well successfully achieved it objectives attaining a final well TD (total depth) of 25,852 ft (7,880 m), a TVD (true vertical depth) of 13,810 ft (4,209 m) and a lateral displacement of 20,150 ft (6142 m). This paper presents the interpreted critical design considerations, details of the operational successes and failures, a summary of the lessons learned and the resulting developed best practice.
Improving Drilling and Completion Performance in the Norwegian North Sea
Authors: Garig Howard A. , Williams Bruce E. 
Published: December 2007

Abstract
Six subsea wells were drilled and completed by Esso Norge AS (ENAS) as part of the Ringhorne development in the Norwegian sector of the North Sea from 15 November 2000 to 2 December 2001. The program was completed in 125 meters of water using a semi-submersible drilling rig. Average well depth was +/− 3500 meters MD and had a vertical section of +/− 2300 meters. The wells were completed as natural sand packs using sand control screens in the horizontal sections. The entire program lasted 383 days and incurred a total of 52.5 days (13.7%) NPT-excluding weather. WOW accounted for 24.8 days (6.5%) NPT. These NPT figures are better than performance achieved by ENAS on the earlier Balder subsea development and below the average time in the industry for similar work.
Three key issues drove the performance on the Ringhorne Project; they were team structure, modification of the rig to program requirements and use of new technology. The Ringhorne drill team was drawn from the original Balder drill team so they were familiar with subsea drilling and completion operations. By applying best practices learned at Balder and incorporating them into the well programs the learning curve on this program was reduced significantly. The rig had most recently been used in a subsea P&A program, so the contractor was also familiar with the issues surrounding a subsea development program. The rig was upgraded with several drilling and completion related items, to optimize it for the upcoming drilling program and running of subsea completions. Some of these modifications were extensive in scope and implementation, such as a subsea equipment skidding system and underhull guidance package. They proved crucial to reducing NPT as well as extending the rig's operating window in harsh weather. The use of new also played a major role in the effectiveness of the project. This included use of a Rotary Closed Loop Steerable drilling system (RCLS) which greatly increased directional drilling performance and delivered a smoother wellbore which allowed for easier completion installation; in spite of longer completion intervals than on the previous program. Wireline intervention on completion installation was reduced by use of pump-open plugs and the use of a low solids oil based mud that eliminated the need for coiled tubing cleanout operations.
This paper reviews the engineering and operations processes used by ENAS to successfully complete this project. Opportunities to apply the learnings on future projects are highlighted.
A New Downhole Tool for ECD Reduction
Authors: Bern P. A. , Hosie Dave , Bansal R. K. , Stewart Donald , Lee Bradley 
Published: December 2007

Abstract
Wellbore pressure management is a critical part of the drilling process. In normal drilling practices, static and dynamic fluid pressures are used to contain formation pressures and to assure wellbore stability. Excessive fluid pressure while circulating can create problems including reduced operating margins between fracture and pore pressures and, in the extreme, lost circulation. To address these problems, an Equivalent Circulation Density (ECD) Reduction Tool (RT) has been developed.
The ECD RT is designed to counter the frictional pressure effects that exist while circulating. The tool is expected to have a broad range of drilling applications including; the narrow pore/fracture pressure margin deepwater environment, wellbores prone to instability, pressure depleted reservoirs, and extended reach wells.
The tool has the potential to: Improve wellbore stabilityExtend hole intervals and reduce casing requirementsImprove well controlReduce lost circulationReduce differential stickingImprove hole cleaning in ERD wells through the use of higher flow rates
This paper describes a new downhole tool for ECD reduction, which is run as an integral part of the drill string. A prototype tool has been built to operate inside 10c3/4″ to 13−3/8″ casing. This tool has undergone laboratory testing and full-scale technology trials are in progress. The design features of this prototype are discussed along with the laboratory test results obtained to date.
Dual Drawworks Provide Operational Redundancy and Reduce Cut and Slip Costs
Authors: Kyllingstad Åge 
Published: December 2007

Abstract
Dual drawworks is a new concept based on the AC gear-driven Active Heave Drawworks. If one of the two independent units fails, the other can still run the block and provide redundancy. Dual drawworks also improves rig efficiency due to higher capacities and savings of cut and slip operations.
Design Considerations and Field Performance of an Advanced Automatic Driller
Authors: Boyadjieff George , Murray Dave , Orr Alan , Porche Mike , Thompson Peter 
Published: December 2007

Abstract
Automatic Drillers have been used for decades. Most of these systems did a poor job of controlling weight on bit, which resulted in equally poor performance. Thus prompting two questions: "What is required to achieve a much better level of control of drilling parameters like weight on bit?" and "What field performance results do we see from improved control?" This paper will address these questions by examining the development and field performance of an advanced automatic drilling system. It will show how the entire system, not just the mechanics or the software, needs to be designed from a control system point of view. It will present the results of field usage of the system, and demonstrating the performance benefits resulting from improved control. Finally, it will suggest future developments for this type of advanced product.