bluuebunny/crossref_metadata_2025_split huggingface dataset:
Remote Operations, the Future of Drilling: Directional Drilling Remote Control
Authors: Gorgone Ignacio , Gomez Juan , Uddenberg Gary 
Published: March 2008

Abstract
As demand for sophisticated drilling technologies has grown rapidly in recent years, the implementation of collaborative centers to improve real-time decision making has become an increasingly attractive option. Emerging technologies now enable real-time transmission of data and voice communications to and from the most remote locations, making it possible to receive and send intelligent commands and respond rapidly to changing circumstances while drilling is in progress. With the proper use of these technologies, it is now possible for a single team of expert personnel to monitor and control multiple complex directional drilling operations from a single remote office.
In the last few years, Schlumberger has created a growing number of collaborative centers to work closely with operators throughout the world. Currently, surface and logging data are transmitted to these centers in real time as part of the drilling optimization process, and real-time data has also been used for completion monitoring and control.
Coinciding with the development of the Operations Support Centers (OSC™) concept, drilling activity increased more quickly than experts could be developed in key areas of operation and support. In such a challenging business environment, the idea of having experts gathered in one room to advise jointly on several simultaneous rig operations has won wide acceptance with the companies which have tried it.
Operations centers, therefore, have become the chief venue for collaboration, data capture, sharing and training, in a way that better meets the needs of fast-growing operations. In particular, the OSC™ concept has made it possible in many cases to reduce crew and support requirements, a significant benefit in today's tightly budgeted operations.
This paper describes the challenges faced in implementing a further step in operations support center, the work process that allows one directional driller and one measurement-while-drilling engineer to control directional drilling operations at several rigs simultaneously, and details the necessary infrastructure, communication systems and operating results. It also provides an insight into the process through a recent project in northern Mexico.
Experimental Study and Modeling of Yield Power-Law Fluid Flow in Annuli with Drillpipe Rotation
Authors: Ahmed Ramadan , Miska Stefan 
Published: March 2008

AbstractHelical flow of non-Newtonian fluids in concentric and eccentric annuli is of great interest in oil/gas well drilling. Experimental results and field measurements demonstrated that frictional pressure loss in the annulus can be affected substantially by the rotation of the drillpipe. Previous studies indicated that the influence of pipe rotation on annular friction pressure loss is affected by fluid properties, flow regime, annular diameter ratio and eccentricity.This article presents results of in-depth experimental and theoretical investigations conducted on the flow of yield power law (Herschel Buckley) fluids in concentric and eccentric annuli with pipe rotation. The aim of this study is to develop a reliable hydraulic model that accounts for the effect of pipe rotation in annular pressure loss calculations.Extensive flow experiments with polymer-based fluids were carried out using a newly developed testing facility. Four different annular geometries have been considered for the investigation. Five different formulations of test fluid were prepared by varying concentrations of Xanthan Gum (XG) and Polyanionic Cellulose (PAC) for each annular geometry. Accurate fluid characterization was made using the horizontal pipe sections and a rotational viscometer. In addition to the experimental work, theoretical analysis of helical flows in concentric annuli was carried out.Experimental results indicate the strong presence of shear thinning and inertial effects when inner pipe rotates. In highly eccentric annuli, inertial effects dominate the phenomenon of shear thinning and result in increased pressure loss as the speed increases. Inertial effects can be generated due eccentricity and/or geometric irregularities of the annulus that substantially influence the velocity field as the pipe rotates. The experimental measurements and theoretical analysis presented in this investigation are very useful for hydraulic program optimization and well control, particularly for managed pressure drilling (MPD) operations.
Troll West Oilfield Development—How a Giant Gas Field Became the Largest Oil Field in the NCS through Innovative Field and Technology Development
Authors: Jones Richard Dyve , Saeverhagen Erland , Thorsen Arve K. , Gard Sveinung 
Published: March 2008

Abstract
The Troll West Oil Field has been, and still is, developed with more than 110 horizontal sub sea wells including 53 multi lateral wells (MLT). Several of the MLT wells have over time been designed and drilled with multiple open hole sidetracks to increase drainage area for each wellhead.
The Troll West Oil Field has been developed from the first test wells drilled in 1984 and 1986, with oil production on stream in 1994 and continuous development still ongoing. The commercial oil reserves on the field have gone from 0 in 1986 to more than 1,400 million barrels today1.
To be able to achieve this tremendous economical upside, the thin oil rim has been developed through sub sea development and extensive horizontal drilling enhancement. The latest development is through extensive use of multilateral drilling and wells containing up to 7 horizontal branches. The process of drilling the MLT wells and the benefit and risk evaluation for the MLT process is discussed and illustrated in this paper.
The additional drainage area gained from open hole sidetracks are delivering additional production to each well head. The unique method used for the open hole sidetracks has proved to be a low risk strategy and highly economical way to get access to additional reserves thus reducing the need for additional sub-sea templates on the field.
This paper shows how the field and technology development has evolved over the last two decades and plans going forward to continue strengthening the Troll West Oil Field production for another 15 years+ prior to the gas drainage. The upcoming technologies are incorporating both drilling and Logging-While-Drilling technologies to enhance the understanding of the mechanics behind the field development.
How Effective is Current Solids Control Equipment for Drilling Fluids Weighted with Micron-Sized Weight Material?
Authors: Massam Jarrod , Stocks Shannon , Oakley Doug , Bremner Colin 
Published: March 2008

Abstract
Centrifuges and shakers are the first defense when managing a drilling fluid against wellbore cuttings and solids contamination. The buildup of drill solids in a fluid can have a detrimental effect on its performance and properties. Much of the solids-control equipment in the field was designed with conventional API-grade weighted fluids in mind, but the increasing use of drilling fluids in the field weighted with micron sized particles has presented a challenge in the use of existing solids-control technologies to achieve effective solids removal.
With a decanting centrifuge, the particle size and density of API-grade barite is such that the centrifugal force tends to remove much of it from the fluid together with the undesired solids. Similarly, the wire mesh size for shaker screens is selected to be effective in removing the cuttings, but consequently, the coarser fraction of the weight material is removed. A significant reduction in weight material particle size has the potential to demonstrate a different behavior. This paper will present data obtained from both the field and from specifically designed yard tests conducted on micronized weighted drilling fluids.
The data discusses solids removal efficiency using different centrifuge designs as well as shaker screen performance, and demonstrates how these can be optimized for the preferential removal of undesirable contaminants and minimize removal of the desired weight material. The operating parameters of the centrifuge have been defined to provide the optimum solids removal efficiency.
Solids analysis, particle size and density results that provide definitive centrifuge parameters for processing fluid weighted with micron-sized material; the results are compared with those parameters obtained from a conventional API-barite weighted fluid showing that lower torque, higher throughputs and lower wear and tear on equipment can be achieved with micronized weighted fluids.
Analysis of Control Lines Strapped to Tubing
Authors: Mitchell Robert F , Ellis S. T. , Siappas G. , Colyer A. 
Published: March 2008

Abstract
Hydraulic control lines are commonly used to actuate surface controlled sub-surface safety valves, and new applications include choke operation and the control of more complex "smartwell" completions. In general, control lines are not subject to routine failures. However, the analysis of world wide completion failures indicates control lines to be a critical component of failure. In fact, control lines and associated components such as clamps and fittings, are not engineered with the same rigor as the rest of the well completion.
The first step in understanding control line failure is predicting the loads and stresses in a control line strapped to the tubing. Tubing movement causes loads in the control line through stretching and bending. To a lesser degree, the tubing is loaded by the control lines. To determine this interaction, a calculation is performed where the control line and the tubing are treated as a composite, with axial displacement constrained to be the same in both. This analysis provides the average stress state in the control line. Because the control line is fixed at only certain points along the tubing, the variation in stress from the average must be determined between clamps. This paper provides the technical details for both calculations.
Several example cases based on field data are presented that give insight into the potential problems that typical production scenarios create for control lines.
Investigation of Factors for Strengthening a Wellbore by Propping Fractures
Authors: Wang Hong (Max) , Soliman Mohamed Y. , Towler Brian F. 
Published: March 2008

Abstract
Wellbore strengthening or stress cage implementation has been recognized as an effective means of dealing with lost circulation during drilling operations. One of the mechanisms developed for strengthening a wellbore has been to prop induced and existing fractures with particulate lost circulation materials (LCM) to effectively increase hoop stress in the near wellbore region.
However, a good understanding of this mechanism is necessary in order to avoid a potentially flawed design and implementation process which could adversely affect job success in the field. One of the main issues is fracture stability under the strengthening conditions. This paper will describe those factors which are important in designing wellbore strengthening jobs and address the conditions necessary to ensure fracture stability, as determined through rock mechanics analysis.
The strengthening of a wellbore by propping fractures has been discussed in a previous investigation.1 In this paper, continuing the previous discussion, various parameters that affect the strengthening of the wellbore are addressed in detail. In-depth discussion of how each of those parameters affects the process of wellbore strengthening is presented. This study was accomplished using a boundary element numerical simulator to facilitate the analyses.
Shallow Hazards Planning in Nigeria Deepwater—Erha-7 Well
Authors: Garcia E. M. , Akers T. J. , Holster J. 
Published: March 2008

Abstract
The Erha-7 well is a deepwater exploration well that was ultimately drilled with a dynamically-positioned rig in 1,074 m water depth within Nigeria's Offshore Mining License (OML) 133 (formerly OPL-209).
During the early well planning process, the site investigation team identified numerous, extensive shallow hazards stacked in the area surrounding the Erha-7 geologic targets. These hazards were evaluated by the drill team, site investigation team, and the business unit to optimize the well location and minimize the risk of encountering shallow gas-charged sands.
The final well location allowed vertical drilling of the riserless conductor-hole interval and required directional drilling below the conductor to intersect vertically stacked geologic targets. Because of the close proximity to numerous shallow hazards and the limited seismic resolution, the final well location was still deemed to possess a moderate risk of encountering gas-charged shallow sands.
This paper discusses the shallow hazards planning involved with the Erha-7 deepwater well. It summarizes the limited industry experience regarding deepwater shallow gas flows and the associated safety considerations. The paper presents the modeling and evaluation of shallow gas flows and dynamic kills used to quantify the potential benefits of drilling a pilot hole, and discusses the sensitivities associated with performing an effective dynamic kill. Finally, a discussion of the dynamic kill plans developed to prevent and effectively mitigate a shallow gas flow.
Successful Drilling Management of Mass Transport Complexes (MTC's) in Deepwater Angola
Authors: Elieff B. A. , Page C. G. , Gupta V. 
Published: March 2008

Abstract
Esso Exploration Angola (Block 15) Limited (EEAL), along with concessionaire Sonangol and co-venturers ENI, BP, and Statoil, are developing several fields in Angola Block 15 (AB 15). Many of the extended reach AB 15 wells have experienced non-productive time (NPT) related to wellbore instability in intervals with shale referred to as Mass Transport Complexes (MTCs). This paper describes the changes made in well design and operational practices that allowed the operator to significantly reduce trouble costs associated with the MTCs.
In late 2006, EEAL, the operating team, and ExxonMobil Upstream Research Company began a campaign to reduce NPT related to wellbore instability, which accounted for 18% of AB 15 rig time in 2006. Numerous changes were made in well design and operational practices including modification of directional trajectories to reduce exposure to MTCs, improved management of wellbore pressure to maintain shale stability, and enhancement of hole cleaning practices in wellbores where significant enlargement could not be prevented. Real-time surveillance practices were also improved to ensure wellbore breakout was detected earlier and corrective measures taken quickly.
Because of the study and changes in practices, the NPT related to wellbore instability decreased from an average of 18.1% of rig time in 2006 to 3.4% in the first three quarters of 2007.
The Use of Multilateral Well Designs for Improved Recovery in Heavy Oil Reservoirs
Authors: Fipke Steven , Celli Adriano 
Published: March 2008

Abstract
There are now a variety of ways to achieve higher recovery factors from heavy oil reservoirs, but most of them involve the injection of thermal energy or chemicals to reduce the oil viscosity. While these techniques have been highly successful, they can also be very expensive when the steam generation and/or chemical injection costs are accumulated throughout the productive life of the field. A lower cost solution, one that has been very successful in the Faja Del Orinoco of Eastern Venezuela, is to use multi-branched wells (multilaterals) to increase reservoir exposure and achieve an arguably higher recovery factor. These multilateral wells have been shown to produce more oil over a longer period of time than conventional horizontal wells without any additional operating costs.
This paper will discuss the concept of using multilateral wells as an alternative to conventional Enhanced Oil Recovery (EOR) techniques in heavy oil reservoirs. It will argue that the oil recovery factor of a reservoir that is drilled with increased wellbore exposure can be comparable to thermal/chemical EOR under the right circumstances, and that the project will have a much lower operating cost. While steam injection has become the successful mainstay of most EOR projects, there are many drawbacks such as the costs of the steam generation and the emission of greenhouse gases. Multilateral wells can potentially offer an option to produce the same reservoir with lower costs while still recovering an increased percentage of the oil from the reservoir. This technique is especially applicable in inter-bedded or thin oil zones where steam injection would be costly and inefficient.
Extensive background information will be presented from the Orinoco belt in Venezuela, where multilateral wells have proven to be an economical approach to develop a very challenging "extra-heavy" oil reservoir.
Reexamination of PDC Bit Walk in Directional and Horizontal Wells
Authors: Chen S. , Collins G. J. , Thomas M. B. 
Published: March 2008

Abstract
This paper describes several mechanisms of PDC bit walk in directional wells drilled by steerable systems and how these mechanisms can be numerically modeled. The developed computer model calculates bit walk rate and walk force with consideration for bit gauge geometry, hole size, formation compressive strength, steering mechanism of the RSS, bit rotational speed, penetration rate and dogleg severity.
Application of the model in Alaskan horizontal wells has revealed that an oversized hole and the bit tilt motion are major causes of the bit walk. A matched bit/RSS system is then provided and the results are very successful: bit walk to the right is avoided and bit steerability is increased significantly.
Total BHA Reliability— An Improved Method to Measure Success
Authors: Brehme Jost , Travis John T. (Tim) 
Published: March 2008

Abstract
Mean Time Between Failure (MTBF) has been a traditional measure of equipment reliability. In the drilling industry, MTBFs of some downhole directional drilling tools are exceeding 1,000 hours, indicating downhole tools have become more reliable and suggesting that tool failures are an unlikely event.
In 2005, ExxonMobil Development Company – Drilling initiated a study on Rotary Steerable System (RSS) and Formation Evaluation (FE) tool failures. Analysis indicated that globally, every third Bottomhole Assembly (BHA) was pulled because of an equipment-related failure. These results did not match the MTBF numbers provided from the service sector.
Further analysis indicated that MTBF is a good metric for a manufacturer to classify the statistical reliability of individual components in a consistent operations environment. However, it is not a good metric for measuring reliability of an entire BHA that consists of many components. As BHAs become more complex, the MTBF of single components must increase in order to maintain existing reliability of the total system.
ExxonMobil is now tracking the RSS performance by run success. This approach favors a total system strategy where each BHA component is evaluated based on its ability to optimize the reliability of the entire BHA.
The four elements of this strategy are: Develop and maintain a reliable data base with defined global input to scale the problemImplement a vendor assessment program to verify that suppliers have a global systematic approach to train staff and maintain toolsAlign with suppliers about realistic load factors and operational envelopes for their toolsTrain users how to select and operate tools for a given application
The goal of the initiative is to have the best tools used in the correct application within drilling parameters that do not exceed the tool design. With this achieved, ExxonMobil expects to see a decrease in failures and reduction in cost not only to the organization but to the service providers as well.
A Novel Heat-Activated RSF to Treat Severe Cases of Lost Circulation: Case Histories from Mexico
Authors: Tirado Guillermo , Pliego Cesar Augusto , Rendon Ariel , Fowler Ian , Marin Jesus , Ramirez Hector Benito , Soriano Eduardo 
Published: March 2008

Abstract
Lost circulation during drilling operations is a costly problem that has plagued the oil and gas industry from its earliest beginnings. Drilling fluids are lost to the formation when the well is drilled overbalanced through high-permeability, fractured, or easily fractured formations. In many cases, total loss of circulation is experienced, and all drilling fluids are lost to the formation with zero returns to surface. This makes cementing casing strings and liners adequately into place difficult.
A range of commonly used conventional lost-circulation materials (LCMs) is available to combat lost circulation. These can be very effective in cases of low permeability or formations with small fractures where cement placement in the loss zone is relatively simple. However, in cases of severe or total lost circulation, the use of these conventional LCMs can often be ineffective. In such cases, attempts are made to stop the losses with the placement of dedicated lost-circulation treatments. These dedicated treatments include specialty cements, gel plugs, or even ordinary cement. However, severe cases of lost circulation continue to be a challenging problem.
This paper discusses field applications in a number of wells in the Burgos Basin of Mexico. A temperature-activated, rigid-setting fluid composition was developed specifically to address the most severe cases of lost circulation. In each of the wells presented, total lost circulation was encountered and treated successfully, allowing drilling operations to resume and the wells to be drilled to the designed depth. This paper details the specific chemical and mechanical characteristics and field performance of the rigid-setting fluid (RSF). It concludes that the combination of unique fluid properties and best practices in fluid placement procedures resulted in a very positive and successful development in the treatment of severe cases of lost circulation in sandstone formations.
Building and Testing a Battery-Operated Subsea Shut-Off System
Authors: Bamford A. S. , Mowat C. A. , Wickramaratne L. S. , Teixeira M. A. 
Published: March 2008

Abstract
A deepwater exploration drilling system has been designed (Leach and Bamford 2005) to deploy a slim, one trip riser from a mono-hull vessel using jetted-in conductor. To deploy the subsea shut-off system from a lightweight monohull vessel it must weigh less than 30 t.
Accumulators become inefficient with increasing water depth as their size and weight needed to store a given quantity of energy increases.
The need for a rapid and reliable method of disconnecting the riser lead to the development and testing of a battery powered shear ram system. Batteries also power the alternative annular cutting tool pipe severance method. This provides an even radial cut for full bore re-entry compared with the belled over profile of sheared pipe.
A prototype subsea pod was built consisting of military specification batteries connected to an electric motor and variable displacement hydraulic pump. By the direct supply of hydraulic fluid to and from the shear rams, high pressure Stack Plate Mounted (SPM) valves are removed from the control system. The resulting high power to weight ratio enabled the pod weight to be kept around 500 kg.
Successful and repeated shear tests were conducted on concentric 194 mm (7–5/8 in) and 140 mm (5–1/2 in) casings with a small battery set without recharge. The results are presented here.
The four pod subsea control system was developed with Triple Modular Redundancy (TMR) architecture. This provides a high degree of reliability and ensures that spurious signals to disconnect are ignored.
It was concluded that a reliable, battery powered subsea pod can operate over the design life of a 100 days well and be charged in-situ using a Remotely Operated Vehicle (ROV).